DTE Energy Company 10-Q
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period ended June 30, 2008
Commission file number 1-11607
DTE ENERGY COMPANY
(Exact name of registrant as specified in its charter)
     
Michigan
(State or other jurisdiction of
incorporation or organization)
  38-3217752
(I.R.S. Employer
Identification No.)
     
2000 2nd Avenue, Detroit, Michigan
(Address of principal executive offices)
  48226-1279
(Zip Code)
313-235-4000
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ     No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a smaller reporting company)    
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o     No þ
At June 30, 2008, 163,095,193 shares of DTE Energy’s common stock were outstanding, substantially all of which were held by non-affiliates.
 
 

 


 

DTE Energy Company
Quarterly Report on Form 10-Q
Quarter Ended June 30, 2008
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Definitions
     
Company
  DTE Energy Company and any subsidiary companies
 
   
CTA
  Costs to achieve, consisting of project management, consultant support and employee severance, related to the Performance Excellence Process
 
   
Customer Choice
  Statewide initiatives giving customers in Michigan the option to choose alternative suppliers for electricity and gas
 
   
Detroit Edison
  The Detroit Edison Company, a direct wholly-owned subsidiary of DTE Energy, and any subsidiary companies
 
   
DTE Energy
  DTE Energy Company, directly or indirectly the parent of Detroit Edison, MichCon and numerous non-utility subsidiaries
 
   
EPA
  United States Environmental Protection Agency
 
   
FERC
  Federal Energy Regulatory Commission
 
   
GCR
  A gas cost recovery mechanism authorized by the MPSC, permitting MichCon to pass the cost of natural gas to its customers
 
   
MDEQ
  Michigan Department of Environmental Quality
 
   
MichCon
  Michigan Consolidated Gas Company, an indirect wholly-owned subsidiary of DTE Energy, and any subsidiary companies
 
   
MISO
  Midwest Independent System Operator, a Regional Transmission Organization
 
   
MPSC
  Michigan Public Service Commission
 
   
Non-utility
  An entity that is not a public utility; its conditions of service, prices of goods and services and other operating related matters are not directly regulated by the MPSC or the FERC
 
   
NRC
  Nuclear Regulatory Commission
 
   
Production tax credits
  Tax credits as authorized under Sections 45K and 45 of the Internal Revenue Code designed to stimulate investment in and development of alternate fuel sources; the amount of a production tax credit can vary each year as determined by the Internal Revenue Service
 
   
Proved reserves
  Estimated quantities of natural gas, natural gas liquids and crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions
 
   
PSCR
  A power supply cost recovery mechanism authorized by the MPSC that allows Detroit Edison to recover through rates its fuel, fuel-related and purchased power expenses
 
   
Securitization
  Detroit Edison financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly owned special purpose entity, the Detroit Edison Securitization Funding LLC
 
   
SFAS
  Statement of Financial Accounting Standards
 
   
Stranded Costs
  Costs incurred by utilities in order to serve customers in a regulated environment that, absent special regulatory approval, would not otherwise be recoverable if customers switch to alternative energy suppliers
 
   
Subsidiaries
  The direct and indirect subsidiaries of DTE Energy Company
 
   
Synfuels
  The fuel produced through a process involving chemically modifying and binding particles of coal, used for power generation and coke production; synfuel production through December 31, 2007 generated production tax credits

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Unconventional Gas
  Includes those oil and gas deposits that originated and are stored in coal bed, tight sandstone and shale formations
 
   
Units of Measurement
   
 
   
Bcf
  Billion cubic feet of gas
 
   
Bcfe
  Conversion metric of natural gas, the ratio of 6 Mcf of gas to 1 barrel of oil
 
   
GWh
  Gigawatthour of electricity
 
   
kWh
  Kilowatthour of electricity
 
   
Mcf
  Thousand cubic feet of gas
 
   
MMcf
  Million cubic feet of gas
 
   
MW
  Megawatt of electricity
 
   
MWh
  Megawatthour of electricity

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Forward-Looking Statements
Certain information presented herein includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve certain risks and uncertainties that may cause actual future results to differ materially from those presently contemplated, projected, estimated or budgeted. Many factors may impact forward-looking statements including, but not limited to, the following:
    the uncertainties of successful exploration of gas shale resources and inability to estimate gas reserves with certainty;
 
    the effects of weather and other natural phenomena on operations and sales to customers, and purchases from suppliers;
 
    economic climate and population growth or decline in the geographic areas where we do business;
 
    environmental issues, laws, regulations, and the cost of remediation and compliance, including potential new federal and state requirements that could include carbon and more stringent mercury emission controls, a renewable portfolio standard and energy efficiency mandates;
 
    nuclear regulations and operations associated with nuclear facilities;
 
    impact of electric and gas utility restructuring in Michigan, including legislative amendments and Customer Choice programs;
 
    employee relations and the impact of collective bargaining agreements;
 
    unplanned outages;
 
    access to capital markets and capital market conditions and the results of other financing efforts which can be affected by credit agency ratings;
 
    the timing and extent of changes in interest rates;
 
    the level of borrowings;
 
    changes in the cost and availability of coal and other raw materials, purchased power and natural gas;
 
    effects of competition;
 
    impact of regulation by the FERC, MPSC, NRC and other applicable governmental proceedings and regulations, including any associated impact on rate structures;
 
    contributions to earnings by non-utility subsidiaries;
 
    changes in and application of federal, state and local tax laws and their interpretations, including the Internal Revenue Code, regulations, rulings, court proceedings and audits;
 
    the ability to recover costs through rate increases;
 
    the availability, cost, coverage and terms of insurance;
 
    the cost of protecting assets against, or damage due to, terrorism;
 
    changes in and application of accounting standards and financial reporting regulations;

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    changes in federal or state laws and their interpretation with respect to regulation, energy policy and other business issues;
 
    amounts of uncollectible accounts receivable;
 
    binding arbitration, litigation and related appeals; and
 
    changes in the economic and financial viability of our suppliers, customers and trading counterparties, and the continued ability of such parties to perform their obligations to the Company.
New factors emerge from time to time. We cannot predict what factors may arise or how such factors may cause our results to differ materially from those contained in any forward-looking statement. Any forward-looking statements refer only as of the date on which such statements are made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.

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Part I — Item 2.
DTE ENERGY COMPANY
Management’s Discussion and Analysis
of Financial Condition and Results of Operations
OVERVIEW
DTE Energy is a diversified energy company with 2007 annual revenues in excess of $8 billion and assets of approximately $24 billion. We are the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales, distribution and storage services throughout southeastern Michigan. We operate four energy-related non-utility segments with operations throughout the United States.
Net income in the second quarter of 2008 was $28 million, or $0.17 per diluted share, compared to net income of $385 million, or $2.20 per diluted share, in the second quarter of 2007. Net income for the six months ended June 30, 2008 was $240 million, or $1.48 per diluted share, compared to net income of $519 million, or $2.95 per diluted share, in the comparable period of 2007. The decreases were due primarily to $359 million in net income resulting from the 2007 gain on the sale of the Antrim shale gas exploration and production business of $897 million ($569 million after-tax), partially offset by losses recognized on related hedges of $323 million ($210 million after-tax), including recognition of amounts previously recorded in accumulated other comprehensive income during the second quarter of 2007. The comparison for the six-month period is also impacted by a 2008 gain of $128 million ($81 million after-tax) on the sale of a portion of the Barnett shale properties.
The items discussed below influenced our current financial performance and may affect future results:
  Effects of weather on utility operations;
 
  Collectibility of accounts receivable on utility operations;
 
  Impact of regulatory decisions on utility operations;
 
  Impact of legislation on utility operations;
 
  Impact of increased market demand on coal supply;
 
  Challenges associated with nuclear fuel;
 
  Discontinuance of planned monetization of our Power and Industrial Projects business;
 
  Monetization of our Unconventional Gas Production business;
 
  Results in our Energy Trading business;
 
  Discontinuance of the Synthetic Fuel business; and
 
  Cost reduction efforts and required environmental and reliability-related capital investments.
Reference in this report to “we,” “us,” “our,” “Company” or “DTE” are to DTE Energy and its subsidiaries, collectively.
UTILITY OPERATIONS
Our Electric Utility segment consists of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 million residential, commercial and industrial customers in southeastern Michigan.
Our Gas Utility segment consists of MichCon and Citizens Gas Fuel Company (Citizens). MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.3 million residential, commercial and industrial customers throughout Michigan. MichCon also has subsidiaries involved in the gathering,

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processing and transmission of natural gas in northern Michigan. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.
Effects of Weather on Utility Operations — Earnings from our utility operations are seasonal and very sensitive to weather. Electric utility earnings are primarily dependent on hot summer weather, while the gas utility’s results are primarily dependent on cold winter weather. During the six months ended June 30, 2008, we experienced colder weather than in the six months ended June 30, 2007.
Additionally, we frequently experience various types of storms that damage our electric distribution infrastructure, resulting in power outages. Restoration and other expenses associated with storm-related power outages were $31 million and $43 million in the three and six months ended June 30, 2008 as compared to $10 million and $29 million in the three and six months ended June 30, 2007.
Collectibility of Accounts Receivable on Utility Operations — Both utilities continue to experience high levels of past due receivables, primarily attributable to economic conditions, higher energy prices and a lack of adequate levels of assistance for low-income customers.
We have taken aggressive actions to reduce the level of past due receivables, including increasing customer disconnections, contracting with collection agencies and working with Michigan officials and others to increase the share of low-income funding allocated to our customers. We experienced an increase in our allowance for doubtful accounts expense for the two utilities to approximately $94 million for the 2008 quarter, in comparison to $39 million for the 2007 quarter. We experienced an increase in allowance for doubtful accounts expense to approximately $136 million during the six months ended June 30, 2008, in comparison to $68 million during the six months ended June 30, 2007.
The April 2005 MPSC gas rate order provided for an uncollectible true-up mechanism for MichCon. MichCon’s operating revenues include a component representing ninety percent of the difference between the actual uncollectible expense for each year and $37 million, including carrying charges. An annual reconciliation proceeding before the MPSC is held. The MPSC approved the 2005 annual reconciliation in December 2006, allowing MichCon to surcharge $11 million beginning in January 2007. The MPSC approved the 2006 annual reconciliation in December 2007, allowing MichCon to surcharge $33 million beginning in January 2008. We filed the 2007 reconciliation in March 2008, requesting an additional surcharge of approximately $34 million including a $1 million uncollected balance from the 2005 surcharge. We accrue interest income on the outstanding balances.
Impact of Regulatory Decisions on Utility Operations — Detroit Edison filed a general rate case in April 2007 requesting a $123 million, or 2.9%, average increase in Detroit Edison’s annual revenue requirement for 2008, and in August 2007 filed a supplement to this filing to account for certain recent events. A July 2007 decision by the Court of Appeals of the State of Michigan remanded back to the MPSC the November 2004 order in a prior Detroit Edison rate case that denied recovery of merger control premium costs. Also, the Michigan legislature enacted the Michigan Business Tax (MBT) in July 2007. The supplemental filing addressed the recovery of the merger control premium costs and the enactment of the MBT. The net impact of the supplemental changes results in an additional revenue requirement of approximately $76 million. In February 2008, Detroit Edison filed an update to its April 2007 rate case filing, which includes the use of 2009 as the projected test year; a revised 2009 load forecast; 2009 estimates on environmental and advanced metering infrastructure capital expenditures; and adjustments to the MBT calculation. An MPSC order related to this filing is expected by early 2009. See Note 6 of the Notes to Consolidated Financial Statements.
The MPSC issued an order in August 2006 approving a settlement agreement providing for an annualized 2006 rate reduction of $53 million for Detroit Edison, effective September 2006. Beginning January 1, 2007 and continuing until April 13, 2008, one year from the April 13, 2007 general rate case filing, rates were reduced by an additional $26 million, for a total reduction of $79 million annually. Detroit Edison experienced a rate reduction of approximately $7 million and $25 million in the three and six months ended June 30, 2008, respectively, and approximately $17 million and $34 million in the three and six months ended June 30, 2007, respectively, as a result of this order. The revenue reduction is net of the recovery of costs associated with the Performance Excellence Process. The settlement agreement provides for some level of realignment of the existing rate structure by allocating

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a larger percentage of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.
In August 2006, MichCon filed an application with the MPSC requesting permission to sell base gas that would become accessible with storage facilities upgrades. In December 2006, MichCon filed its 2007-2008 GCR plan case proposing a maximum GCR factor of $8.49 per Mcf. In August 2007, a settlement agreement in this proceeding was approved by the MPSC that provides for a sharing with customers of the proceeds from the sale of base gas. In addition, the agreement provides for a rate case filing moratorium until January 1, 2009, unless certain unanticipated changes occur that impact income by more than $5 million. MichCon’s gas storage enhancement projects, the main subject of the aforementioned settlement, have enabled 17 billion cubic feet (Bcf) of gas to become available for cycling. Under the settlement terms, MichCon delivered 13.4 Bcf of this gas to its customers through 2007 at a savings to market-priced supplies of approximately $54 million. This settlement provides for MichCon to retain the proceeds from the sale of 3.6 Bcf of gas, which MichCon expects to sell through 2009. During 2007, MichCon sold 0.75 Bcf of base gas and recognized a pre-tax gain of $5 million. MichCon did not sell base gas in the first six months of 2008. In July 2008, MichCon filed an application with the MPSC requesting permission to sell an additional 4 Bcf of base gas that will become available for sale as a result of better than expected operations at its storage fields. MichCon proposed to sell 1.3 Bcf of the base gas to GCR customers during the 2009-2010 GCR period at cost and to sell the remaining 2.7 Bcf to non-system supply customers in 2009 at market prices. MichCon requested that the MPSC treat the proceeds from the sale of the 2.7 Bcf of base gas to non-system supply customers as a one-time increase in MichCon’s net income, and not include the proceeds in the calculation of MichCon’s revenue requirements in future rate cases.
Impact of Legislation on Utility Operations – In April 2008, a package of bills to establish a sustainable, long-term energy plan was passed by the Michigan House of Representatives. Key provisions of the bills include:
    A 10 percent limit on the electric Customer Choice program. Once customers representing 10 percent of a utility’s load have elected to receive their generation from an alternate electricity supplier, remaining customers would be maintained on full, bundled utility service. As of June 30, 2008, approximately 2 percent of Detroit Edison’s load was on the electric Customer Choice program. The bill also codifies prior MPSC requirements for customers returning to full utility service.
 
    A requirement that the MPSC set rates based on cost-of-service for all customer classes, eliminating the current subsidy for residential customers included in business customer rates. Elimination of the subsidy (de-skewing) would be phased in over a five year period. Rates for schools and other qualified educational institutions would be immediately set at their cost of service.
 
    A 12 month hard-stop deadline for the MPSC to complete a rate case and the ability for the utility to self-implement rate changes six months after a rate filing, bringing Michigan in line with many other states. If the final rate case order leads to lower rates than the utility had self-implemented, the utility would refund, with interest, the difference. In addition, utility rate cases would be based on a forward test year. The bill also provides organizational changes which may enable the MPSC to obtain increased funding to hire staff to meet the new timetable.
 
    A Certificate of Need (CON) process for capital projects costing more than $500 million. The MPSC would be required to review for prudency proposed investments in new generating assets, acquisition of existing power plants, major upgrades of power plants, and long-term power purchase agreements. Utilities would also be provided the opportunity to recover interest expense during construction.
 
    A review and approval process, including evaluation criteria, for the MPSC for proposed utility merger and acquisitions in Michigan.
 
    A renewable portfolio standard (RPS) of 4% by 2012 and 10% by 2015. Qualifying renewable energy sources would include wind, biomass, solar, hydro, geothermal, waste industrial gases and industrial thermal energy. After passage of the new law, the MPSC would establish a per meter surcharge to fund the RPS requirements. The monthly surcharge is limited to $3 for residential customers, $16.58 for commercial customers and $187.50 for industrial customers. The recovery mechanism starts prior to actual construction

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      in order to smooth the rate impact for customers. Within 5 months of the passage of the new law, the utilities would file an RPS plan with the MPSC. A utility will not have to comply with the RPS standards if the MPSC determines that the added costs of meeting the RPS standard exceed the per meter caps. The bills specify that a utility can build up to 33 percent of the generation required to meet the RPS. An additional 33 percent would be developed by others and sold to the utility. The remaining renewable generation would be contracted through long-term power purchase agreements (PPA).
    A requirement for utilities to create specific efficiency programs for each customer class including incentives for meeting performance goals. For electric sales, the program would target 0.3 percent annual savings in 2008/2009, ramping up to 1 percent annual savings by 2012. For natural gas sales, the targeted annual savings start at 0.1 percent in 2008/2009 before ramping up to 0.75 percent by 2012. The MPSC may allow a utility to recover over time the actual costs of its efficiency programs in base rates. Costs would be limited to 2 percent maximum of total utility revenues (1.5 percent of business revenues). The bill would also allow a natural gas utility that spends at least 0.5 percent of its revenues on energy efficiency programs to decouple revenues from volumetric sales, adjusting for sales volumes above or below forecasted levels. Similar to the RPS bills, a cost test would be implemented to ensure reasonable costs. If a utility spends at the MPSC approved levels, it would be considered in full compliance even if the savings targets are not met.
In June 2008, a package of bills to establish a sustainable, long-term energy plan was passed by the Michigan Senate. Key provisions of the bills passed by the Michigan Senate that differ from the package of bills passed by the Michigan House of Representatives in April 2008 include:
    A requirement that the MPSC set rates based on cost-of-service for all customer classes, eliminating the current subsidy for residential customers and certain business customers included in business customer rates. Elimination of the subsidy (de-skewing) would be phased in over a five year period for certain business customers and over a ten year period for residential customers.
 
    A combined renewable portfolio standard (RPS) and energy efficiency impacts of 2% by 2011, 4% by 2012, 6% by 2014 and 7% by 2015.
The next step in the process is the reconcilement of the bills passed by the Michigan House of Representatives and the Michigan Senate and approval of a final energy reform plan. Two House-Senate conference committees have been appointed to resolve differences in the energy package. We are unable to predict the timing and outcome of the legislative process and the impact of the legislative process on the Company.
Impact of Increased Market Demand on Coal Supply - Our generating fleet produces approximately 79% of its electricity from coal. Increasing coal demand from domestic and international markets has resulted in significant price increases which are passed to our customers through the PSCR. In addition, difficulty in recruiting workers, obtaining environmental permits and finding economically recoverable amounts of new coal have resulted in decreasing coal output from the central Appalachian region. Furthermore, as a result of environmental regulation and declining eastern coal stocks, demand for cleaner burning western coal has increased.
Challenges Associated with Nuclear Fuel - We operate one nuclear facility that undergoes a periodic refueling outage approximately every eighteen months. Uranium prices have been rising due to supply concerns. In the future, there may be additional nuclear facilities constructed in the industry that may place additional pressure on uranium supplies and prices. We have a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. We are obligated to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold; this fee is a component of nuclear fuel expense. Delays have occurred in the DOE’s program for the acceptance and disposal of spent nuclear fuel at a permanent repository. We are a party in litigation against the DOE for both past and future costs associated with the DOE’s failure to accept spent nuclear fuel under the timetable set forth in the Federal Nuclear Waste Policy Act of 1982. Until the DOE is able to fulfill its obligation under the contract, we are responsible for the spent nuclear fuel storage and have begun work on an on-site dry cask storage facility.

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NON-UTILITY OPERATIONS
We have made significant investments in non-utility asset-intensive businesses. We employ disciplined investment criteria when assessing opportunities that leverage our assets, skills and expertise. Specifically, we invest in targeted energy markets with attractive competitive dynamics where meaningful scale is in alignment with our risk profile. As part of a strategic review of our non-utility operations, we have taken various actions including the sale, restructuring or recapitalization of certain non-utility businesses.
Beginning in the second quarter of 2008, we have realigned our Coal Transportation and Marketing business from the Coal and Gas Midstream segment to the Power and Industrial Projects segment due to changes in how financial information is evaluated and resources allocated to segments by senior management. The Company’s segment information reflects this change for all periods presented. See Note 10 of the Notes to Consolidated Financial Statements for further information on this realignment.
Gas Midstream
Gas Midstream owns partnership interests in two interstate transmission pipelines and two natural gas storage fields. The pipeline and storage assets are primarily supported by stable, long-term, fixed-price revenue contracts. The assets of these businesses are well integrated with other DTE Energy operations. Pursuant to an operating agreement, MichCon provides physical operations, maintenance and technical support for Washington 28 and Washington 10 storage facilities. In addition, pursuant to a separate agreement, MichCon provides physical operations, maintenance and technical support for a portion of the Vector Pipeline system which MichCon leases to Vector. Gas Midstream is continuing its steady growth plan with two new storage capacity expansions and the expanding and building of new pipeline capacity to serve markets in the Midwest and Northeast United States.
Unconventional Gas Production
Our Unconventional Gas Production business is engaged in natural gas exploration, development and production primarily within the Barnett shale in north Texas. We continue to develop our position here, with total leasehold acreage of 62,462 (60,634 acres, net of interest of others). We continue to acquire select positions in active development areas in the Barnett shale to optimize our existing portfolio.
Monetization of our Unconventional Gas Production Business – In 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $260 million. The properties sold included 186 Bcf of proved and probable reserves on approximately 11,000 net acres in the core area of the Barnett shale. The Company recognized a cumulative pre-tax gain of $128 million ($81 million after-tax) on the sale during 2008.
We plan to continue to develop our holdings in the western portion of the Barnett shale and to seek opportunities for additional monetization of select properties within our Barnett shale holdings, when conditions are appropriate. We invested approximately $60 million in the Barnett shale for the first six months of 2008 and expect to invest an additional $35 million to $40 million during the remainder of the year. During 2008, we expect to drill 30 to 35 new wells and achieve Barnett shale production of approximately 5 Bcfe of natural gas from our remaining properties, compared with approximately 7.7 Bcfe in 2007 from all properties, including those that were sold.
Power and Industrial Projects
Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers, coal transportation and marketing and biomass energy projects. This business provides utility-type services using project assets usually located on or near the customers’ premises in the steel, automotive, pulp and paper, airport and other industries. Services include pulverized coal and petroleum coke supply, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. We own and operate one gas-fired peaking electric generating plant and a biomass-fired electric generating plant. This business also develops, owns and operates landfill gas recovery systems throughout the United States, and produces metallurgical coke from three coke batteries. The production of coke from two of these coke batteries generates production tax credits. The business provides coal transportation services including fuel, transportation, storage, blending and rail equipment management services. We specialize in minimizing fuel costs and maximizing reliability of supply for energy-intensive customers. Additionally, we participate in coal marketing and the purchase and sale of emissions credits. This business performs coal mine methane extraction, in

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which we recover methane gas from mine voids for processing and delivery to natural gas pipelines, industrial users or for small power generation projects. We expanded our coal storage and blending capacity with the start of commercial operation of our coal terminal in Chicago in April 2007.
Discontinuance of Planned Monetization of our Power and Industrial Projects Business – During the third quarter of 2007, we announced our plans to sell a 50% interest in a portfolio of select Power and Industrial Projects. As a result, the assets and liabilities of the Projects were classified as held for sale at that time. During the second quarter of 2008, the United States asset sale market has weakened and challenges in the debt market have persisted. Additionally, the performance of the portfolio of select Power and Industrial Projects has improved. As a result of these developments, our work on this planned monetization has been discontinued. As of June 30, 2008, the assets and liabilities of the Projects were no longer classified as held for sale.
Energy Trading
Energy Trading focuses on physical power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, optimization of contracted natural gas pipelines and storage, and power transmission and generating capacity positions. Our customer base is predominantly utilities, local distribution companies, pipelines and other marketing and trading companies. We enter into derivative financial instruments as part of our marketing and hedging activities. Most of the derivative financial instruments are accounted for under the mark-to-market method, which results in the recognition of unrealized gains and losses from changes in the fair value of the derivatives in our results of operations. We utilize forwards, futures, swaps and option contracts to mitigate risk associated with our marketing and trading activity as well as for proprietary trading within defined risk guidelines. Energy Trading also provides commodity risk management services to the other businesses within DTE Energy.
Results in our Energy Trading Business — Significant portions of the electric and gas marketing and trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as contracted natural gas pipelines and storage and power generation capacity positions. Most financial instruments are deemed derivatives, whereas proprietary gas inventory, power transmission, pipelines and certain storage assets are not derivatives. As a result, this segment may experience earnings volatility as derivatives are marked-to-market without revaluing the underlying non-derivative contracts and assets. This results in gains and losses that are recognized in different accounting periods. We may incur mark-to-market accounting gains or losses in one period that could reverse in subsequent periods.
DISCONTINUED OPERATIONS
Synthetic Fuel
Due to the expiration of synfuel production tax credits at the end of 2007, the Synthetic Fuel business ceased operations and was classified as a discontinued operation effective December 31, 2007. Synfuel plants chemically changed coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits were provided for the production and sale of solid synthetic fuel produced from coal and were available through December 31, 2007. The synthetic fuel plants generated operating losses that were substantially offset by production tax credits. The value of a production tax credit is adjusted annually by an inflation factor and published annually by the Internal Revenue Service (IRS). The value is reduced if the Reference Price of a barrel of oil exceeds certain thresholds. The actual tax credit phase-out for 2007 was approximately 67%.
PERFORMANCE EXCELLENCE PROCESS
We continuously review and adjust our cost structure and seek improvements in our processes. In 2005, we initiated a company-wide review of our operations called the Performance Excellence Process. This initiative was an extension of the DTE Energy Operating System initiative adopted in 2002. These initiatives represent the application of tools and operating practices that have resulted in operating efficiencies, inventory reductions and improvements in technology systems, among other enhancements.

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The primary goal is to become more competitive by reducing costs, eliminating waste and optimizing business processes while improving customer service. Many of our customers are under intense economic pressure and will benefit from our efforts to keep down our costs and their rates. Additionally, we will need significant resources in the future to invest in the infrastructure required to provide safe, reliable and affordable energy. Specifically, we began a series of focused improvement initiatives within our Electric and Gas Utilities, and our corporate support function. The process is rigorous and challenging and seeks to yield sustainable performance improvements for our customers and shareholders. We have identified continuous improvement opportunities, including the Performance Excellence Process. To fully realize the benefits from this program, it was necessary to make significant up-front investments in our infrastructure and business processes, and we began to realize sustained net cost savings in 2007.
In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison and MichCon, commencing in 2006, to defer the incremental costs to achieve (CTA), subject to the MPSC establishing a recovery mechanism. Further, the order provides for Detroit Edison and MichCon to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. Detroit Edison deferred approximately $102 million and $54 million of CTA in 2006 and 2007, respectively, as a regulatory asset and began amortizing deferred costs in 2007 as the recovery of these costs was provided for by the MPSC in the order approving the settlement in the show cause proceeding. Amortization of prior year deferred CTA costs was $4 million and $2 million for the three months ended June 30, 2008 and 2007, respectively, and $8 million and $5 million for the six months ended June 30, 2008 and 2007, respectively. Detroit Edison deferred approximately $7 million and $8 million of CTA for the three months ended June 30, 2008 and 2007, respectively, and approximately $11 million and $21 million of CTA for the six months ended June 30, 2008 and 2007, respectively. MichCon cannot defer CTA costs at this time because a regulatory recovery mechanism has not been established by the MPSC. MichCon expects to seek a recovery mechanism in its next rate case in 2009.
CAPITAL INVESTMENT
We anticipate significant capital investment across all of our business segments. Most of our capital expenditures will be concentrated within our utility segments. From 2008 through 2012, our electric utility segment currently expects to invest approximately $5.3 billion (excluding investments in new generation capacity, if any), including increased environmental requirements and reliability enhancement projects. Our gas utility segment currently expects to invest approximately $1.0 billion on system expansion, pipeline safety and reliability enhancement projects through the same period. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment.
OUTLOOK
The next few years will be a period of rapid change for DTE Energy and for the energy industry. Our strong utility base, combined with our integrated non-utility operations, position us well for long-term growth.
Looking forward, we will focus on several areas that we expect will improve future performance:
    Continuing to pursue regulatory stability and investment recovery for our utilities;
 
    Managing the growth of our utility asset base;
 
    Enhancing our cost structure across all business segments;
 
    Improving our Electric and Gas Utility customer satisfaction; and
 
    Investing in businesses that integrate our assets and leverage our skills and expertise.
We will continue to pursue opportunities to grow our businesses in a disciplined manner if we can secure opportunities that meet our strategic, financial and risk criteria.

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RESULTS OF OPERATIONS
Net income in the second quarter of 2008 was $28 million, or $0.17 per diluted share, compared to net income of $385 million, or $2.20 per diluted share, in the second quarter of 2007. Net income for the six months ended June 30, 2008 was $240 million, or $1.48 per diluted share, compared to net income of $519 million, or $2.95 per diluted share, in the comparable period of 2007. The decreases were due primarily to $359 million in net income resulting from the 2007 gain on the sale of the Antrim shale gas exploration and production business of $897 million ($569 million after-tax), partially offset by losses recognized in 2007 on related hedges of $323 million ($210 million after-tax), including recognition of amounts previously recorded in accumulated other comprehensive income. The comparison for the six-month period is also impacted by a 2008 gain of $128 million ($81 million after-tax) on the sale of a portion of the Barnett shale properties.
Segments realigned – Beginning in the second quarter of 2008, we have realigned our Coal Transportation and Marketing business from the Coal and Gas Midstream segment to the Power and Industrial Projects segment due to changes in how financial information is evaluated and resources allocated to segments by senior management. The Company’s segment information reflects this change for all periods presented. See Note 10 of the Notes to Consolidated Financial Statements for further information on this realignment.
The following sections provide a detailed discussion of the operating performance and future outlook of our segments.
Net income by segment for the three and six month periods ended June 30, 2008 and 2007 is as follows:
                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
(in Millions)   2008     2007     2008     2007  
Net Income:
                               
Electric Utility
  $ 51     $ 60     $ 92     $ 100  
Gas Utility
    (11 )     (7 )     48       60  
Non-Utility Operations:
                               
Gas Midstream
    8       8       16       16  
Unconventional Gas Production
    4       (211 )     86       (209 )
Power and Industrial Projects
    (6 )     9       4       17  
Energy Trading
    (14 )     (13 )     17       (12 )
 
                               
Corporate & Other
    (4 )     502       (35 )     472  
 
                               
Income (Loss) from Continuing Operations:
                               
Utility
    40       53       140       160  
Non-utility
    (8 )     (207 )     123       (188 )
Corporate & Other
    (4 )     502       (35 )     472  
 
                       
 
    28       348       228       444  
Discontinued Operations
          37       12       75  
 
                       
Net Income
  $ 28     $ 385     $ 240     $ 519  
 
                       

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ELECTRIC UTILITY
Our Electric Utility segment consists of Detroit Edison.
Factors impacting income: Net income decreased by $9 million in the second quarter of 2008 and decreased by $8 million for the six-month period ended June 30, 2008. These decreases were primarily due to lower gross margins, partially offset by lower operation and maintenance, and depreciation and amortization expenses.
                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
(in Millions)   2008     2007     2008     2007  
Operating Revenues
  $ 1,173     $ 1,210     $ 2,326     $ 2,304  
Fuel and Purchased Power
    415       402       817       756  
 
                       
Gross Margin
    758       808       1,509       1,548  
Operation and Maintenance
    369       380       727       728  
Depreciation and Amortization
    178       198       370       380  
Taxes Other Than Income
    60       69       122       141  
Other Asset (Gains), Losses and Reserves, Net
          (1 )           6  
 
                       
Operating Income
    151       162       290       293  
Other (Income) and Deductions
    71       72       145       143  
Income Tax Provision
    29       30       53       50  
 
                       
Net Income
  $ 51     $ 60     $ 92     $ 100  
 
                       
 
                               
Operating Income as a Percentage of Operating Revenues
    13 %     13 %     12 %     13 %
Gross margin decreased $50 million in the second quarter of 2008 and $39 million in the six-month period ended June 30, 2008. The decreases in 2008 were primarily due to the absence of the favorable impact of a May 2007 MPSC order related to the 2005 PSCR reconciliation and the unfavorable impacts of weather and service territory performance. The decreases were partially offset by higher rates attributable to the April 2008 expiration of a rate reduction related to the MPSC show cause proceeding and higher margins due to customers returning from the electric Customer Choice program. Revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism. See Note 6 of the Notes to Consolidated Financial Statements.
The following table details changes in various gross margin components relative to the comparable prior period:
Increase (Decrease) in Gross Margin Components Compared to Prior Year
                 
(in Millions)   Three Months     Six Months  
Weather related impacts
  $ (20 )   $ (19 )
Return of customers from electric Customer Choice
    6       14  
Service territory performance
    (16 )     (7 )
Refundable pension cost
    (11 )     (14 )
2005 PSCR reconciliation order in 2007
    (34 )     (34 )
April 2008 expiration of show-cause rate decrease
    12       12  
Other, net
    13       9  
 
           
Decrease in gross margin
  $ (50 )   $ (39 )
 
           

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    Three Months Ended     Six Months Ended  
Power Generated and Purchased   June 30     June 30  
(in Thousands of MWh)   2008     2007     2008     2007  
Power Plant Generation
                               
Fossil
    10,347       10,117       20,587       20,674  
Nuclear
    2,408       2,415       4,751       4,843  
 
                       
 
    12,755       12,532       25,338       25,517  
Purchased Power
    1,509       1,887       3,239       3,120  
 
                       
System Output
    14,264       14,419       28,577       28,637  
Less Line Loss and Internal Use
    (722 )     (624 )     (1,567 )     (1,408 )
 
                       
Net System Output
    13,542       13,795       27,010       27,229  
 
                       
 
                               
Average Unit Cost ($/MWh)
                               
Generation (1)
  $ 17.98     $ 14.75     $ 17.30     $ 15.09  
 
                       
Purchased Power
  $ 61.53     $ 68.45     $ 61.56     $ 66.64  
 
                       
Overall Average Unit Cost
  $ 22.59     $ 21.77     $ 22.31     $ 20.70  
 
                       
 
(1)   Represents fuel costs associated with power plants.
                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
(in Thousands of MWh)   2008     2007     2008     2007  
Electric Sales
                               
Residential
    3,428       3,718       7,360       7,504  
Commercial
    4,913       4,871       9,275       9,179  
Industrial
    3,231       3,322       6,747       6,696  
Wholesale
    700       715       1,423       1,451  
Other
    87       89       196       199  
 
                       
 
    12,359       12,715       25,001       25,029  
Interconnections sales (1)
    1,183       1,080       2,009       2,200  
 
                       
Total Electric Sales
    13,542       13,795       27,010       27,229  
 
                       
 
                               
Electric Deliveries
                               
Retail and Wholesale
    12,359       12,715       25,001       25,029  
Electric Customer Choice
    284       323       682       774  
Electric Customer Choice — Self Generators (2)
    12       200       70       267  
 
                       
Total Electric Sales and Deliveries
    12,655       13,238       25,753       26,070  
 
                       
 
(1)   Represents power that is not distributed by Detroit Edison.
 
(2)   Represents deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements.
Operation and maintenance expense decreased $11 million in the second quarter of 2008 and $1 million in the six-month period ended June 30, 2008. The decrease for the second quarter was primarily due to the absence of $27 million of 2007 Enterprise Business Systems (EBS) implementation costs, lower benefits expense of $12 million and $5 million attributable to continuous improvement initiatives, partially offset by higher storm expense of $21 million and higher uncollectible expenses of $19 million. The decrease in the six-month period was due primarily to the absence of $27 million of 2007 EBS implementation costs and lower benefit expenses of $18 million, partially offset by higher storm expense of $14 million, higher uncollectible expense of $29 million and higher labor and other expenses of $7 million.
Depreciation and amortization expense decreased $20 million in the second quarter of 2008 and $10 million in the six-month period ended June 30, 2008 due primarily to decreased amortization of regulatory assets.
Taxes other than income decreased $9 million in the second quarter of 2008 and $19 million in the six-month period ended June 30, 2008 due to the Michigan Single Business Tax (SBT) expense in 2007, which was replaced with the Michigan Business Tax (MBT) in 2008. The MBT is accounted for in the Income tax provision.

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Other asset (gains), losses and reserves, net decreased $1 million in the second quarter of 2008 and decreased $6 million in the six-month period ended June 30, 2008 due to a $1 million gain on sale of an asset in the 2007 second quarter and a $7 million reserve established in the six-month 2007 period for a loan guaranty related to our former ownership of a steam heating business now owned by Thermal Ventures II, LP (Thermal).
Outlook – We will move forward in our efforts to continue to improve the operating performance and cash flow of Detroit Edison. We continue to resolve outstanding regulatory issues and continue to pursue additional regulatory and/or legislative solutions for structural problems within the Michigan electric market, primarily electric Customer Choice and the need to adjust rates for each customer class to reflect the full cost of service. We are also seeking regulatory reform to ensure more timely cost recovery and resolution of rate cases. If enacted, these issues would be addressed, for the most part, by the package of bills to establish a sustainable long-term energy plan recently passed by the Michigan House of Representatives and Michigan Senate, discussed more fully in the Overview section. Looking forward, additional issues, such as rising prices for coal and other commodities, health care and higher levels of capital spending, will result in us taking meaningful action to address our costs while continuing to provide quality customer service. We will continue to seek opportunities to improve productivity, remove waste and decrease our costs while improving customer satisfaction.
Long term, we will be required to invest an estimated $2.4 billion on emission controls through 2018. We intend to seek recovery of these investments in future rate cases.
Additionally, our service territory may require additional generation capacity. A new base-load generating plant has not been built within the State of Michigan in over 20 years. Should our regulatory environment be conducive to such a significant capital expenditure, we may build, upgrade or co-invest in a base-load coal facility or a new nuclear plant. We have not decided on construction of a new base-load nuclear plant; however, in February 2007 we announced preparation of a license application for construction and operation of a new nuclear power plant on the site of Fermi 2. By completing the license application before the end of 2008, we may qualify for financial incentives under the Federal Energy Policy Act of 2005.
The following variables, either individually or in combination, could impact our future results:
    The amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals or new legislation;
 
    Our ability to reduce costs and maximize plant and distribution system performance;
 
    Variations in market prices of power, coal and gas;
 
    Economic conditions within Michigan and corresponding impacts on demand for electricity;
 
    Collectibility of accounts receivable;
 
    Weather, including the severity and frequency of storms;
 
    The level of customer participation in the electric Customer Choice program; and
 
    Any potential new federal and state environmental, renewable energy and energy efficiency requirements.

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GAS UTILITY
Our Gas Utility segment consists of MichCon and Citizens.
Factors impacting income: Gas Utility’s net loss increased $4 million in the second quarter of 2008, and net income in the 2008 six-month period was $12 million lower due primarily to higher operation and maintenance expense, partially offset by higher gross margins.
                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
(in Millions)   2008     2007     2008     2007  
Operating Revenues
  $ 397     $ 311     $ 1,312     $ 1,185  
Cost of Gas
    216       162       870       785  
 
                       
Gross Margin
    181       149       442       400  
Operation and Maintenance
    148       113       271       224  
Depreciation and Amortization
    26       24       50       45  
Taxes Other Than Income
    12       15       26       29  
Other Asset Losses and Reserves, Net
                      3  
 
                       
Operating Income
    (5 )     (3 )     95       99  
Other (Income) and Deductions
    10       6       25       18  
Income Tax Provision
    (4 )     (2 )     22       21  
 
                       
Net Income (Loss)
  $ (11 )   $ (7 )   $ 48     $ 60  
 
                       
 
                               
Operating Income as a Percentage of Operating Revenues
    (1 )%     (1 )%     7 %     8 %
Gross margin increased $32 million in the second quarter of 2008 and $42 million in the six-month period ended June 30, 2008. The increase in the second quarter is due primarily to higher revenue of $33 million associated with the uncollectible tracking mechanism and $8 million of transportation revenue, partially offset by $4 million of lower storage services, $4 million as a result of customer conservation and lower volumes and $1 million due to the unfavorable impact of weather. The increase in the six-month period is due primarily to higher revenue associated with the uncollectible tracking mechanism of $33 million, the $9 million favorable impact of lower lost gas recognized, higher natural gas transportation revenue of $4 million and $2 million due to the favorable impact of weather, partially offset by $4 million as a result of customer conservation and lower volumes and $4 million of lower storage services. Revenues include a component for the cost of gas sold that is recoverable through the GCR mechanism.
                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
    2008     2007     2008     2007  
Gas Markets (in Millions)
                               
Gas sales
  $ 322     $ 239     $ 1,141     $ 1,012  
End user transportation
    32       28       83       80  
 
                       
 
    354       267       1,224       1,092  
Intermediate transportation
    16       11       35       30  
Storage and other
    27       33       53       63  
 
                       
 
  $ 397     $ 311     $ 1,312     $ 1,185  
 
                       
 
                               
Gas Markets (in Bcf)
                               
Gas sales
    19       22       90       92  
End user transportation
    23       24       67       72  
 
                       
 
    42       46       157       164  
Intermediate transportation
    122       94       238       222  
 
                       
 
    164       140       395       386  
 
                       
Operation and maintenance expense increased $35 million in the second quarter of 2008 and $47 million in the six-month period ended June 30, 2008, primarily due to increases in uncollectible expenses of $37 million and $47 million, respectively. The increases in uncollectible expense are partially offset by increased revenues from the uncollectible tracking mechanism included in gross margin discussed above.

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Depreciation and amortization expense increased $2 million in the second quarter of 2008 and $5 million in the six-month period ended June 30, 2008 due to higher levels of depreciable plant. In the six-month period ended June 30, 2007, we recorded a $3 million adjustment resulting from an MPSC order related to pipeline assets.
Other asset losses and reserves, net decreased $3 million in the six-month period ended June 30, 2008. In the six-month period ended June 30, 2007, we recorded a $3 million adjustment attributable to an MPSC disallowance of certain costs related to the acquisition of pipeline assets.
Outlook — Operating results are expected to vary due to regulatory proceedings, weather, changes in economic conditions, customer conservation, process improvements, volatility in the short-term storage markets which impact third party storage revenues and the timing of base gas sales. Higher gas prices and economic conditions have resulted in continued pressure on receivables and working capital requirements that are partially mitigated by the MPSC’s uncollectible true-up mechanism and GCR mechanism.
We will continue to seek opportunities to improve productivity, remove waste and decrease our costs while improving customer satisfaction.
NON-UTILITY OPERATIONS
Gas Midstream
Our Gas Midstream segment consists of our gas pipelines and storage business.
Factors impacting income: Increased storage contract revenues, offset by a non-recurring 2007 gain and a higher tax provision due to the MBT in 2008, resulted in flat net income performance in 2008 as compared to 2007. Operating revenues in the six-month period were higher due primarily to increased capacity sold in long-term agreements.
                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
(in Millions)   2008     2007     2008     2007  
Operating Revenues
  $ 17     $ 17     $ 34     $ 33  
Operation and Maintenance
    3       4       7       6  
Depreciation and Amortization
    1       2       3       3  
Taxes Other Than Income
                1       1  
Other Asset (Gains), Losses and Reserves, net
          (1 )           (1 )
 
                       
Operating Income
    13       12       23       24  
Other (Income) and Deductions
    (1 )     (1 )     (5 )     (2 )
Income Tax Provision
    6       5       12       10  
 
                       
Net Income
  $ 8     $ 8     $ 16     $ 16  
 
                       
Outlook — Our Gas Midstream business expects to continue its steady growth plan. In April 2008, Washington 28’s increased storage capacity of 1.8 Bcf was placed in service, increasing the total capacity to 16 Bcf. Also, in April 2008, Washington 10’s Shelby 2 storage field was placed in service creating an additional 4 Bcf of storage capacity. The Shelby 2 storage capacity will be expanded over the next several months to a total capacity of 8 Bcf, increasing Washington 10’s storage capacity to a total of 74 Bcf. Vector Pipeline placed into service its Phase 1 expansion for approximately 200 MMcf/d in November 2007. In addition, Vector Pipeline received FERC approval in June 2008 to build one additional compressor station and to expand the Vector Pipeline by approximately 100 MMcf/d, with a proposed in-service date of November 1, 2009. Adding another compressor station will bring the system from its current capacity of about 1.2 Bcf/d up to 1.3 Bcf/d in 2009. Both the 2007 and 2009 expansion projects are supported by customers under long-term contracts. Gas Midstream has a 26% ownership interest in Millennium Pipeline which commenced construction in June 2007 and is scheduled to be in service in late 2008. Millennium Pipeline currently has nearly 85% of its capacity sold to customers under long-term contracts.
Unconventional Gas Production
Our Unconventional Gas Production business is engaged in natural gas exploration, development and production primarily within the Barnett shale in northern Texas. In June 2007, we sold our Antrim shale gas exploration and production business in northern Michigan for gross proceeds of $1.3 billion.

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In 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $260 million. The properties sold included 186 Bcf of proved and probable reserves on approximately 11,000 net acres in the core area of the Barnett shale. We recognized a gain of $128 million ($81 million after-tax) on the sale in 2008.
Factors impacting income: The 2007 results reflect the recording of $323 million of losses on financial contracts related to expected Antrim gas production and sales through 2013. The 2008 six-month results include a gain of $128 million ($81 million after-tax) recognized on the sale of our Barnett shale property. In addition, lower gas sales volumes were offset by higher commodity prices and higher gas and oil production from retained wells in 2008 compared to 2007.
                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
(in Millions)   2008     2007     2008     2007  
Operating Revenues
  $ 13     $ (287 )   $ 23     $ (259 )
Operation and Maintenance
    5       14       11       25  
Depreciation, Depletion and Amortization
    3       7       5       14  
Taxes Other Than Income
          4             7  
Other Asset (Gains) and Losses, Reserves and Impairments, net
    (2 )     9       (128 )     9  
 
                       
Operating Income
    7       (321 )     135       (314 )
Other (Income) and Deductions
    1       3       1       7  
Income Tax Provision (Benefit)
    2       (113 )     48       (112 )
 
                       
Net Income (Loss)
  $ 4     $ (211 )   $ 86     $ (209 )
 
                       
Operating revenues increased $300 million in the second quarter of 2008 and $282 million in the 2008 six-month period. The improvements reflect the recording of $323 million of losses during the 2007 periods on financial contracts that hedged our price risk exposure related to expected Antrim gas production and sales through 2013. These financial contracts were accounted for as cash flow hedges, with changes in estimated fair value of the contracts reflected in other comprehensive income. Upon the sale of Antrim, the financial contracts no longer qualified as cash flow hedges. The contracts were retained and offsetting financial contracts were put into place to effectively settle these positions. In conjunction with the Antrim sale and effective settlement of these contract positions, Antrim reclassified amounts held in accumulated other comprehensive income and recorded the effective settlements, reducing operating revenues in the 2007 periods by $323 million. Excluding the impact of the losses on the Antrim hedges, operating revenues decreased $23 million and $41 million in the three and six months ended June 30, 2008 as compared to the same periods in 2007. The decreases were principally due to lower natural gas sales volumes as a result of our monetization initiatives, partially offset by higher commodity prices and higher gas and oil production on retained wells.
Operation and maintenance expense was lower by $9 million and $14 million in the second quarter and six-month period ended June 30, 2008, respectively, as a result of our monetization initiatives. For the six-month period ended June 30, 2008, Barnett shale production was approximately 2.2 Bcfe compared with approximately 3.4 Bcfe during the same period in 2007.
Outlook — We plan to continue to develop our holdings in the western portion of the Barnett shale and to seek opportunities for additional monetization of select properties within our Barnett shale holdings, when conditions are appropriate. We invested approximately $60 million in the Barnett shale for the first six months of 2008 and expect to invest an additional $35 million to $40 million during the remainder of the year. During 2008, we expect to drill 30 to 35 new wells and achieve Barnett shale production of approximately 5 Bcfe of natural gas from our remaining properties, compared with approximately 7.7 Bcfe in 2007 from all properties, including those that were sold.
Power and Industrial Projects
Our Power and Industrial Projects segment is comprised primarily of projects that deliver utility-type products and services to industrial, commercial and institutional customers, biomass energy projects and coal transportation and marketing.
During the third quarter of 2007, we announced our plans to sell a 50% interest in a portfolio of select Power and Industrial Projects. As a result, the assets and liabilities of the Projects were classified as held for sale at that time and the Company ceased recording depreciation and amortization expense related to these assets. During the second

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quarter of 2008, the United States asset sale market has weakened and challenges in the debt market have persisted. Additionally, the performance of the portfolio of select Power and Industrial Projects has improved. As a result of these developments, our work on this planned monetization has been discontinued. As of June 30, 2008, the assets and liabilities of the Projects were no longer classified as held for sale. Depreciation and amortization resumed in June 2008 when the assets were reclassified as held and used.
Factors impacting income: We incurred a net loss of $6 million in the 2008 second quarter as compared to $9 million net income in 2007. Net income decreased $13 million in the six-month period ended June 30, 2008.
                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
(in Millions)   2008     2007     2008     2007  
Operating Revenues
  $ 263     $ 351     $ 514     $ 674  
Operation and Maintenance
    246       331       484       628  
Depreciation and Amortization
    8       9       11       20  
Taxes Other Than Income
    3       3       7       7  
Asset (Gains) Losses and Reserves, Net
    16       (1 )     13        
 
                       
Operating Income
    (10 )     9       (1 )     19  
Other (Income) and Deductions
          3       (3 )     9  
Minority Interest
    1       (1 )     1       (3 )
Income Taxes
                               
Provision (Benefit)
    (3 )           1       3  
Production Tax Credits
    (2 )     (2 )     (4 )     (7 )
 
                       
 
    (5 )     (2 )     (3 )     (4 )
 
                       
Net Income (Loss)
  $ (6 )   $ 9     $ 4     $ 17  
 
                       
Operating revenues decreased $88 million in the second quarter of 2008 and $160 million in the six-month period ended June 30, 2008.
Operation and maintenance expense decreased $85 million in the second quarter of 2008 and $144 million in the six-month period ended June 30, 2008.
The decreases are primarily a result of reduced coal transportation volume, partially offset by an increase in coal trading activity, for which operating revenues and operation and maintenance expense are reported net.
Assets (gains) losses and reserves, net expense increased $17 million in the second quarter of 2008 and $13 million in the six-month period ended June 30, 2008. These losses are primarily attributable to a loss of approximately $19 million related to the valuation adjustment for the cumulative depreciation and amortization upon reclassification of certain project assets as held and used. Partially offsetting this loss were gains attributable to the sale of one of our coke battery projects where the proceeds were dependent on future production.
Outlook — Power and Industrial Projects will continue leveraging its extensive energy-related operating experience and project management capability to develop and grow the on-site energy business. We expect to see a negative impact on net income through the rest of 2008, since approximately $11 million of our annual 2007 coal transportation and marketing business net income was dependent upon our Synfuel operations that ceased operations at the end of 2007.
Energy Trading
Our Energy Trading segment focuses on physical power and gas marketing, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, optimization of contracted natural gas pipelines and storage, and power transmission and generating capacity positions.

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Factors impacting income: Energy Trading’s 2008 second quarter net loss was $1 million greater than the 2007 second quarter net loss. Net income increased $29 million in the six-month period ended June 30, 2008.
                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
(in Millions)   2008     2007     2008     2007  
Operating Revenues
  $ 435     $ 197     $ 723     $ 408  
Fuel, Purchased Power and Gas
    430       203       649       396  
 
                       
Gross Margin
    5       (6 )     74       12  
Operation and Maintenance
    17       11       33       24  
Depreciation, Depletion and Amortization
    2       1       3       2  
Taxes Other Than Income
          1       1       1  
 
                       
Operating Income
    (14 )     (19 )     37       (15 )
Other (Income) and Deductions
    2       1       3       3  
Income Tax Provision
    (2 )     (7 )     17       (6 )
 
                       
Net Income (Loss)
  $ (14 )   $ (13 )   $ 17     $ (12 )
 
                       
Gross margin increased $11 million in the second quarter of 2008 and increased $62 million in the six-month period ended June 30, 2008.
The second quarter 2008 increase is due primarily to an increase in unrealized margins of $18 million, partially offset by lower realized margins of $8 million for the second quarter of 2008. The increase in unrealized margins consisted of $30 million of favorability due to the absence of mark-to-market losses in the second quarter of 2007 reflecting revisions of valuation estimates for natural gas contracts, $22 million of current year mark to market gains in our power portfolio, primarily in transmission optimization and $6 million in our oil trading portfolio due to timing related losses in 2007. This favorability is partially offset by $40 million mark to market losses largely in our gas storage strategies. The decrease in realized margins consisted of $13 million from our power strategies, partially offset by $5 million improvement in realized margins from our gas strategies.
The increase for the six-month period is due to higher unrealized margins of $39 million and higher realized margins of $22 million. The increase in unrealized margins include mark to market favorability of $36 million in our power strategies, due primarily to transmission optimization and $27 million in our gas trading strategies. Additionally, the absence of $30 million in mark-to-market losses in the second quarter of 2007 reflecting revisions of valuation estimates for natural gas contracts contributed to current year to date favorability. Partially offsetting this favorability is $54 million of current year mark to market losses predominately from our gas storage and transportation portfolios. Higher realized margins consisted of $42 million from our gas strategies, primarily gas storage, partially offset by $22 million from our power marketing and transmission optimization strategies.
Operation and maintenance expense increased $6 million in the second quarter of 2008 and $9 million in the six-month period ended June 30, 2008 due to higher payroll and incentive costs.
Outlook — Significant portions of the Energy Trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as capacity positions of natural gas storage, natural gas pipelines, and power transmission and full requirements contracts. The financial instruments are deemed derivatives, whereas the proprietary gas inventory, pipelines, transmission contracts, certain full requirements contracts and storage assets are not derivatives. As a result, we will experience earnings volatility as derivatives are marked-to-market without revaluing the underlying non-derivative assets. The majority of such earnings volatility is associated with the natural gas storage cycle, which does not coincide with the calendar year, but runs annually from April of one year to March of the next year. Energy Trading’s strategy is to economically manage the price risk of storage with futures and over-the-counter forwards and swaps. This results in gains and losses that are recognized in different interim and annual accounting periods.
See also the “Fair Value” section that follows.

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CORPORATE & OTHER
Corporate & Other results include various corporate staff functions. These functions support the entire Company; therefore, their costs are fully allocated to the various segments based on services utilized. As a result, the effect of the allocation on each segment can vary from year to year. Corporate & Other also holds certain non-utility debt and energy-related investments.
Factors impacting income: Corporate & Other results were lower by $506 million in the second quarter of 2008 and $507 million in the 2008 six-month period, due primarily to the 2007 gain on the sale of the Antrim shale gas exploration and production business of approximately $897 million ($569 million after-tax), partially offset by effective income tax rate adjustments.
DISCONTINUED OPERATIONS
Synthetic Fuel
We discontinued the operations of our synthetic fuel production facilities throughout the United States as of December 31, 2007. Synfuel plants chemically changed coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits were provided for the production and sale of solid synthetic fuel produced from coal and were available through December 31, 2007. The synthetic fuel business generated operating losses that were substantially offset by production tax credits.
The incentive provided by production tax credits was designed to reduce and phase out if the price of oil increased to the point of providing significant market incentives for the production of synthetic fuels. As such, the tax credit in a given year was phased out if the reference price of oil within that year exceeded a threshold price. As of December 31, 2007, the reference price exceeded the threshold and the tax credit value was reduced by an estimated phase-out percentage of 69%. Reserves for expected refunds of partner payments for production tax credits were recorded at December 31, 2007 based on this estimated phase-out percentage. An adjustment to the reserves was recorded in the first quarter of 2008 to reflect the actual 67% phase-out percentage based on the actual IRS Reference Price and inflation factor published by the IRS in March 2008. This adjustment to the phase-out percentage resulted in a pre-tax gain from discontinued operations of $12 million during the six-month period ended June 30, 2008.
                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
(in Millions)   2008     2007     2008     2007  
Operating Revenues
  $     $ 262     $ 7     $ 529  
Operation and Maintenance
    1       314       9       638  
Depreciation, Depletion and Amortization
    (1 )     2       (2 )     3  
Taxes Other Than Income
    (1 )     4       (1 )     8  
Asset (Gains), Losses and Reserves, Net
    1       (41 )     (15 )     (77 )
 
                       
Operating Income (Loss)
          (17 )     16       (43 )
Other (Income) and Deductions
    (1 )     (2 )     (2 )     (6 )
Minority Interest
    2       (56 )     2       (115 )
Income Taxes
                               
Provision
    (1 )     14       5       27  
Production Tax Credits
          (10 )     (1 )     (24 )
 
                       
 
    (1 )     4       4       3  
 
                       
Net Income
  $     $ 37     $ 12     $ 75  
 
                       
Operating revenues decreased $262 million in the second quarter of 2008 and $522 million for the six-month period ended June 30, 2008 due to the cessation of operations of our synfuel facilities at December 31, 2007. The 2008 activity reflects the increased value of 2007 synfuel production as a result of final determination of the IRS Reference Price and inflation factor.
Operation and maintenance expense decreased $313 million in the second quarter of 2008 and $629 million in the six-month period ended June 30, 2008 due to the cessation of operations of our synfuel facilities at December 31,

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2007. The 2008 activity reflects adjustments to 2007 contractually defined cost sharing mechanisms with suppliers, as determined by applying the actual phase-out percentage.
Asset (gains), losses and reserves, net decreased $42 million in the second quarter of 2008 and $62 million in the six-month period ended June 30, 2008 due to the cessation of operations of our synfuel facilities at December 31, 2007. The 2008 activity reflects the impact of reserve adjustments for the final phase-out percentage.
CUMULATIVE EFFECT OF ACCOUNTING CHANGES AND NEW ACCOUNTING PRONOUNCEMENTS
Effective January 1, 2008, we adopted SFAS No. 157, Fair Value Measurements. The cumulative effect adjustment upon adoption of SFAS No. 157 represented a $4 million increase to the January 1, 2008 balance of retained earnings. As permitted by FASB Staff Position FAS 157-2, we have deferred the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009. See also the “Fair Value” section.
See also Notes 2 and 3 of the Notes to Consolidated Financial Statements.
CAPITAL RESOURCES AND LIQUIDITY
Cash Requirements
We use cash to maintain and expand our electric and gas utilities and to grow our non-utility businesses, retire and pay interest on long-term debt and pay dividends. During the first six months of 2008, our cash requirements were met primarily through operations and from our non-utility monetization program. We believe that we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements.
                 
    Six Months Ended  
    June 30  
(in Millions)   2008     2007  
Cash and Cash Equivalents
               
Cash Flow From (Used For)
               
Operating activities:
               
Net income
  $ 240     $ 519  
Depreciation, depletion and amortization
    440       467  
Deferred income taxes
    180       (4 )
Gain on sale of non-utility assets
    (128 )     (897 )
Gain on sale of synfuel and other assets, net
    (3 )     (67 )
Working capital and other
    806       980  
 
           
 
    1,535       998  
 
           
 
               
Investing activities:
               
Plant and equipment expenditures — utility
    (544 )     (480 )
Plant and equipment expenditures — non-utility
    (110 )     (141 )
Proceeds from sale of non-utility assets
    253       1,258  
Proceeds from sale of synfuels and other assets
    2       216  
 
               
Restricted cash and other investments
    (53 )     (42 )
 
           
 
    (452 )     811  
 
           
 
               
Financing activities:
               
Issuance of long-term debt
    798        
Redemption of long-term debt
    (154 )     (111 )
Repurchase of long-term debt
    (238 )      
Short-term borrowings, net
    (984 )     (330 )
Repurchase of common stock
    (16 )     (333 )
Dividends on common stock and other
    (178 )     (189 )
 
           
 
    (772 )     (963 )
 
           
Net Increase in Cash and Cash Equivalents
  $ 311     $ 846  
 
           

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Cash from Operating Activities
A majority of our operating cash flow is provided by our electric and gas utilities, which are significantly influenced by factors such as weather, electric Customer Choice, regulatory deferrals, regulatory outcomes, economic conditions and operating costs. Our non-utility businesses also provide sources of cash flow to the enterprise, primarily from the synthetic fuels business, which we believe, subject to considerations discussed below, will provide up to approximately $200 million of net cash impacts in 2008 and 2009.
Cash from operations in the six months ended June 30, 2008 increased $537 million from the comparable 2007 period. The operating cash flow increase primarily reflects higher net income after adjusting for non-cash and non-operating items (depreciation, depletion and amortization, deferred taxes and gains on sales of assets) and cash held as collateral associated with trading counterparty transactions.
Cash from Investing Activities
Cash inflows associated with investing activities are primarily generated from the sale of assets, while cash outflows are primarily generated from plant and equipment expenditures. Net cash used for investing activities was $452 million for the six months ended June 30, 2008, compared with cash from investing activities of $811 million in the same period in 2007. The change was primarily driven by our non-utility monetization program.
Cash from Financing Activities
We rely on both short-term borrowings and long-term financing as a source of funding for our capital requirements not satisfied by our operations. Short-term borrowings, which are mostly in the form of commercial paper borrowings, provide us with the liquidity needed on a daily basis. Our commercial paper program is supported by our unsecured credit facilities.
Net cash used for financing activities decreased $191 million during the six months ended June 30, 2008 compared to the same period in 2007, primarily due to the issuance of long-term debt and lower repurchases of common stock, partially offset by the repurchase of tax-exempt bonds and the repayment of short-term borrowings.
Outlook
We expect cash flow from operations to increase over the long-term primarily due to improvements from higher earnings at our utilities. We have incurred costs associated with implementation of our Performance Excellence Process, but we began to realize sustained net cost savings in 2007. We may also be impacted by the delayed collection of underrecoveries of our PSCR and GCR costs and electric and gas accounts receivable as a result of MPSC orders. Energy prices are likely to be a source of volatility with regard to working capital requirements for the foreseeable future. We are continuing our efforts to identify opportunities to improve cash flow through working capital initiatives.
We anticipate approximately $200 million of net synfuel-related cash impacts in 2008 and 2009, which consists of the final reconciliation of cash from synthetic fuel operations (related to activity prior to December 31, 2007), proceeds from option hedges, and tax credit carryforward utilization and other tax benefits that are expected to reduce future tax payments.
As part of a strategic review of our non-utility operations, we have taken various actions including the sale, restructuring or recapitalization of certain non-utility businesses that generated approximately $900 million in after-tax cash proceeds in 2007 and an additional approximately $170 million in the first six months of 2008 from the sale of a portion of Barnett shale properties. Proceeds from the monetization activities were used to repurchase common stock and redeem outstanding debt. Our objectives for cash redeployment are to increase shareholder value; strengthen the balance sheet and coverage ratios; improve our current credit rating and outlook; and to have any monetization be accretive to earnings per share.
In July 2008, we experienced approximately $600 million of cash outflows related to synfuel partner refunds and the return of trading counterparty cash held as collateral.

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We continue to monitor the impact, if any, of the current conditions in the credit markets on our operations. We believe that our access to financing at reasonable interest rates and the fair value of assets held in trust to satisfy future obligations for nuclear decommissioning and pension plans will not be significantly affected by current conditions in the credit market.
FAIR VALUE
SFAS No. 157 — Fair Value Measurements
Effective January 1, 2008, we adopted SFAS No. 157. The cumulative effect adjustment upon adoption of SFAS No. 157 represented a $4 million increase to the January 1, 2008 balance of retained earnings. As permitted by FASB Staff Position FAS 157-2, we have deferred the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009. See Note 3 of the Notes to Consolidated Financial Statements.
Derivative Accounting
The accounting standards for determining whether a contract meets the criteria for derivative accounting are numerous and complex. Moreover, significant judgment is required to determine whether a contract requires derivative accounting, and similar contracts can sometimes be accounted for differently. If a contract is accounted for as a derivative instrument, it is recorded in the financial statements as “Assets or Liabilities from risk management and trading activities,” at the fair value of the contract. The recorded fair value of the contract is then adjusted at each reporting date, in the Consolidated Statements of Operations, to reflect any change in the fair value of the contract, a practice known as mark-to-market (MTM) accounting. Changes in the fair value of a designated derivative that is highly effective as a cash flow hedge are recorded as a component of Accumulated other comprehensive income, net of taxes, until the hedged item affects income. These amounts are subsequently reclassified into earnings as a component of the value of the forecasted transaction, in the same period as the forecasted transaction affects earnings. The ineffective portion of the fair value changes is recognized in the Consolidated Statements of Operations immediately.
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. To determine the fair value of contracts accounted for as derivative instruments, we use a combination of quoted market prices, published indexes and mathematical valuation models. Valuation models require various inputs, including forward prices, volatility, interest rates and exercise periods.
Contracts we typically classify as derivative instruments include power, gas, certain coal and oil forwards, futures, options and swaps, and foreign currency contracts. Items we do not generally account for as derivatives (and which are therefore excluded from the following tables) include proprietary gas inventory, certain gas storage and transportation arrangements, and gas and oil reserves.
The subsequent tables contain the following four categories represented by their operating characteristics and key risks:
    Proprietary Trading — Represents derivative activity transacted with the intent of taking a view, capturing market price changes, or putting capital at risk. This activity is speculative in nature as opposed to hedging an existing exposure.
 
    Structured Contracts — Represents derivative activity transacted by originating substantially hedged positions with wholesale energy marketers, producers, end users, utilities, retail aggregators and alternative energy suppliers.
 
    Economic Hedges — Represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with owned transportation and storage capacity. Changes in the value of derivatives in this category economically offset changes in the value of underlying non-derivative positions, which do not qualify for fair value accounting. The difference

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      in accounting treatment of derivatives in this category and the underlying non-derivative positions can result in significant earnings volatility.
    Other — Primarily represents derivative activity associated with our gas reserves. A portion of the price risk associated with anticipated production from the Barnett gas reserves has been mitigated through 2010. Changes in the value of the hedges are recorded as “Assets or Liabilities from risk management and trading activities,” with an offset in Other comprehensive income to the extent that the hedges are deemed effective. The amounts shown in the following tables exclude the value of the underlying gas reserves including changes therein.
Roll-Forward of MTM Energy Contract Net Assets
The following tables provide details on changes in our MTM net asset (or liability) position for the six months ended June 30, 2008:
                                         
    Proprietary     Structured     Economic              
(in Millions)   Trading     Contracts     Hedges     Other     Total  
MTM at December 31, 2007
  $ 8     $ (365 )   $ 4     $ 2     $ (351 )
 
                             
Reclassify to realized upon settlement
    46       (127 )     (10 )     (1 )     (92 )
Changes in fair value recorded to income
    41       108       (17 )     2       134  
Amortization of option premiums
    (1 )                       (1 )
 
                             
Amounts recorded to unrealized income
    86       (19 )     (27 )     1       41  
Cumulative effect adjustment to initially apply SFAS No. 157, pre-tax
          6                   6  
Amounts recorded in other comprehensive income
                      (17 )     (17 )
Change in collateral held by (for) others
    (40 )     (329 )                 (369 )
Option premiums paid and other
    (12 )     2                   (10 )
 
                             
MTM at June 30, 2008
  $ 42     $ (705 )   $ (23 )   $ (14 )   $ (700 )
 
                             
A substantial portion of the Company’s price risk related to its Antrim shale gas exploration and production business was mitigated by financial contracts that hedged our price risk exposure through 2013. The contracts were retained when the Antrim business was sold and offsetting financial contracts were put into place to effectively settle these positions. The contracts will require payments through 2013. These contracts represent a significant portion of the above net mark-to-market liability.
The following table provides a current and noncurrent analysis of “Assets and Liabilities from risk management and trading activities,” as reflected on the Consolidated Statements of Financial Position as of June 30, 2008. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.
                                                 
    Proprietary     Structured     Economic                     Assets  
(in Millions)   Trading     Contracts     Hedges     Eliminations     Other     (Liabilities)  
Current assets
  $ 121     $ 390     $ 17     $ (19 )   $ 5     $ 514  
Noncurrent assets
    41       330       1       (9 )           363  
 
                                   
Total MTM assets
    162       720       18       (28 )     5       877  
 
                                   
 
                                               
Current liabilities
    (116 )     (692 )     (17 )     19       (12 )     (818 )
Noncurrent liabilities
    (4 )     (733 )     (24 )     9       (7 )     (759 )
 
                                   
Total MTM liabilities
    (120 )     (1,425 )     (41 )     28       (19 )     (1,577 )
 
                                   
 
                                               
Total MTM net assets (liabilities)
  $ 42     $ (705 )   $ (23 )   $     $ (14 )   $ (700 )
 
                                   

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Maturity of Fair Value of MTM Energy Contract Net Assets
We manage our MTM risk on a portfolio basis based upon the delivery period of our contracts and the individual components of the risks within each contract. Accordingly, we record and manage the energy purchase and sale obligations under our contracts in separate components based on the commodity (e.g. electricity or gas), the product (e.g. electricity for delivery during peak or off-peak hours), the delivery location (e.g. by region), the risk profile (e.g. forward or option), and the delivery period (e.g. by month and year).
We determine the MTM adjustment for our derivative contracts from a combination of quoted market prices, published indexes and mathematical valuation models. We generally derive the pricing for our contracts from active quotes or external resources. Actively quoted indexes include exchange-traded positions such as the New York Mercantile Exchange and the Intercontinental Exchange, and over-the-counter positions for which broker quotes are available. For periods or locations in which external market data is not readily observable, we estimate value using mathematical valuation models. We periodically update our policy and valuation methodologies for changes in market liquidity and other assumptions which may impact the estimated fair value of our derivative contracts.
As a result of adherence to generally accepted accounting principles, the tables above do not include the expected earnings impacts of certain non-derivative gas storage and power contracts. Consequently, gains and losses from these positions may not match with the related physical and financial hedging instruments in some reporting periods, resulting in volatility in DTE Energy’s reported period-by-period earnings; however, the financial impact of this timing difference will reverse at the time of physical delivery and/or settlement.
The table below shows the maturity of our MTM positions:
                                         
                            2011        
(in Millions)                           and     Total Fair  
Source of Fair Value   2008     2009     2010     Beyond     Value  
Proprietary Trading
  $ (19 )   $ 61     $     $     $ 42  
Structured Contracts
    (153 )     (280 )     (109 )     (163 )     (705 )
Economic Hedges
    (7 )     (1 )     (2 )     (13 )     (23 )
Other
    (4 )     (7 )     (3 )           (14 )
 
                             
Total
  $ (183 )   $ (227 )   $ (114 )   $ (176 )   $ (700 )
 
                             

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Part I — Item 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk
DTE Energy has commodity price risk in both utility and non-utility businesses arising from market price fluctuations.
The Electric and Gas utility businesses have risks in connection with the anticipated purchases of coal, natural gas, uranium, electricity and base metals to meet their service obligations. However, the Company does not bear material exposure to earnings risk as such changes are comprehended in regulatory rate recovery mechanisms. Regulatory rate-recovery occurs in the form of PSCR and GCR mechanisms and a tracking mechanism to mitigate some losses from customer migration due to electric Customer Choice programs. See Note 6 of the Notes to Consolidated Financial Statements.
The Company is exposed to short term cash flow or liquidity risk as a result of the time differential between actual cash settlements and regulatory rate recovery. DTE manages this risk through timely regulatory filings, interim rate relief proceedings, tracking mechanisms and long term supply contracts, where possible.
Our Gas Midstream business segment has exposure to natural gas price fluctuations. Gas Midstream manages its exposure through the sale of long-term storage and transportation contracts.
Our Unconventional Gas Production business segment has exposure to natural gas and, to a lesser extent, crude oil price fluctuations. These commodity price fluctuations can impact both current year earnings and reserve valuations. To manage this exposure, we may use forward energy contracts and swaps. Approximately 45% of 2008 production is hedged.
Our Power and Industrial Projects segment is subject to crude oil, electricity, natural gas and coal-based product price risk. To manage this exposure, we may use forward energy, capacity and futures contracts.
Our Energy Trading business segment has exposure to electricity, natural gas, crude oil, heating oil and foreign currency price fluctuations. These risks are managed through its energy marketing and trading operations through the use of forward energy, capacity, storage, options and futures contracts, within pre-determined risk parameters.
Credit Risk
Bankruptcies
We purchase and sell electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail and other industries. Certain of our customers have filed for bankruptcy protection under Chapter 11 of the U. S. Bankruptcy Code. We regularly review contingent matters relating to these customers and our purchase and sale contracts and we record provisions for amounts considered at risk of probable loss. We believe our previously accrued amounts are adequate for probable loss. The final resolution of these matters is not expected to have a material effect on our financial statements.
Other
We engage in business with customers that are non-investment grade. We closely monitor the credit ratings of these customers and, when deemed necessary, we request collateral or guarantees from such customers to secure their obligations.

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Energy Trading
We are exposed to credit risk through trading activities. Credit risk is the potential loss that may result if our trading counterparties fail to meet their contractual obligations. We utilize both external and internally generated credit assessments when determining the credit quality of our trading counterparties. The following table displays the credit quality of our trading counterparties as of June 30, 2008:
                         
    Credit Exposure              
    before Cash     Cash     Net Credit  
(in Millions)   Collateral     Collateral     Exposure  
Investment Grade (1)
                       
A- and Greater
  $ 824     $ (402 )   $ 422  
BBB+ and BBB
    133       (1 )     132  
BBB-
    29             29  
 
                 
Total Investment Grade
    986       (403 )     583  
Non-investment grade (2)
    193       (29 )     164  
Internally Rated — investment grade (3)
    161             161  
Internally Rated — non-investment grade (4)
    19       (10 )     9  
 
                 
Total
  $ 1,359     $ (442 )   $ 917  
 
                 
 
(1)   This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investors Service (Moody’s) and BBB- assigned by Standard & Poor’s Rating Group, a division of the McGraw-Hill Companies, Inc. (Standard & Poor’s). The five largest counterparty exposures combined for this category represented approximately 47% of the total gross credit exposure.
 
(2)   This category includes counterparties with credit ratings that are below investment grade. The five largest counterparty exposures combined for this category represented approximately 13% of the total gross credit exposure.
 
(3)   This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, but are considered investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately 7% of the total gross credit exposure.
 
(4)   This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, and are considered non-investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately 1% of the total gross credit exposure.
Interest Rate Risk
We are subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we may use treasury locks and interest rate swap agreements. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). As of June 30, 2008, we had a floating rate debt-to-total debt ratio of approximately 4% (excluding securitized debt).
Foreign Currency Risk
We have foreign currency exchange risk arising from market price fluctuations associated with fixed priced contracts. These contracts are denominated in Canadian dollars and are primarily for the purchase and sale of power as well as for long-term transportation capacity. To limit our exposure to foreign currency fluctuations, we have entered into a series of currency forward contracts through January 2013. Additionally, we may enter into fair value currency hedges to mitigate changes in the value of contracts or loans.

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Summary of Sensitivity Analysis
We performed a sensitivity analysis on the fair values of our commodity contracts, long-term debt instruments and foreign currency forward contracts. The sensitivity analysis involved increasing and decreasing forward rates at June 30, 2008 by a hypothetical 10% and calculating the resulting change in the fair values. The following represents the results of the sensitivity analysis calculations:
                         
(in Millions)   Assuming a 10%   Assuming a 10%    
Activity   increase in rates   decrease in rates   Change in the fair value of
Coal Contracts
  $ (1 )   $ 1     Commodity contracts
Gas Contracts
  $ (7 )   $ 9     Commodity contracts
Power Contracts
  $ 22     $ (22 )   Commodity contracts
Interest Rate Risk
  $ (308 )   $ 334     Long-term debt
Foreign Currency Risk
  $ (7 )   $ (9 )   Forward contracts

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Part I — Item 4.
CONTROLS AND PROCEDURES
(a) Evaluation of disclosure controls and procedures
Management of the Company carried out an evaluation, under the supervision and with the participation of DTE Energy’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in the Securities Exchange Act Rules 13a-15(e) and 15d-15(e)) as of June 30, 2008, which is the end of the period covered by this report. Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that such controls and procedures are effective in providing reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.
(b) Changes in internal control over financial reporting
There have been no changes in the Company’s internal control over financial reporting during the quarter ended June 30, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Part I — Item 1.
DTE Energy Company
Consolidated Statements of Operations (Unaudited)
                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
(in Millions, Except per Share Amounts)   2008     2007     2008     2007  
Operating Revenues
  $ 2,251     $ 1,677     $ 4,821     $ 4,139  
 
                       
 
                               
Operating Expenses
                               
Fuel, purchased power and gas
    1,032       698       2,298       1,833  
Operation and maintenance
    754       796       1,453       1,530  
Depreciation, depletion and amortization
    216       240       442       464  
Taxes other than income
    78       110       158       200  
Gain on sale of non-utility assets
    (2 )     (897 )     (128 )     (897 )
Other asset (gains) and losses, reserves and impairments, net
    16       9       12       19  
 
                       
 
    2,094       956       4,235       3,149  
 
                       
 
                               
Operating Income
    157       721       586       990  
 
                       
 
                               
Other (Income) and Deductions
                               
Interest expense
    122       134       246       270  
Interest income
    (4 )     (9 )     (8 )     (14 )
Other income
    (18 )     (6 )     (40 )     (24 )
Other expenses
    9       10       23       18  
 
                       
 
    109       129       221       250  
 
                       
 
                               
Income Before Income Taxes and Minority Interest
    48       592       365       740  
 
                               
Income Tax Provision
    18       243       134       294  
 
                               
Minority Interest
    2       1       3       2  
 
                       
 
                               
Income from Continuing Operations
    28       348       228       444  
 
                               
Discontinued Operations
                               
Income (loss) from discontinued operations, net of tax
    2       (19 )     14       (40 )
Minority interest in discontinued operations
    2       (56 )     2       (115 )
 
                       
 
          37       12       75  
 
                               
Net Income
  $ 28     $ 385     $ 240     $ 519  
 
                       
 
                               
Basic Earnings per Common Share
                               
Income from continuing operations
  $ 0.17     $ 2.00     $ 1.41     $ 2.53  
Discontinued operations
          0.21       0.07       0.43  
 
                       
Total
  $ 0.17     $ 2.21     $ 1.48     $ 2.96  
 
                       
 
                               
Diluted Earnings per Common Share
                               
Income from continuing operations
  $ 0.17     $ 1.99     $ 1.41     $ 2.52  
Discontinued operations
          0.21       0.07       0.43  
 
                       
Total
  $ 0.17     $ 2.20     $ 1.48     $ 2.95  
 
                       
 
                               
Weighted Average Common Shares Outstanding
                               
Basic
    162       174       162       175  
Diluted
    163       175       163       176  
Dividends Declared per Common Share
  $ 0.53     $ 0.53     $ 1.06     $ 1.06  
See Notes to Consolidated Financial Statements (Unaudited)

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DTE Energy Company
Consolidated Statements of Financial Position (Unaudited)
                 
    June 30     December 31  
(in Millions)   2008     2007  
ASSETS
               
Current Assets
               
Cash and cash equivalents
  $ 445     $ 123  
Restricted cash
    86       140  
Accounts receivable (less allowance for doubtful accounts of $269 and $182, respectively)
               
Customer
    1,557       1,658  
Other
    320       514  
Accrued power and gas supply cost recovery revenue
    47       76  
Inventories
               
Fuel and gas
    379       429  
Materials and supplies
    204       204  
Deferred income taxes
    207       387  
Assets from risk management and trading activities
    514       181  
Other
    135       196  
Current assets held for sale
          83  
 
           
 
    3,894       3,991  
 
           
 
               
Investments
               
Nuclear decommissioning trust funds
    794       824  
Other
    559       446  
 
           
 
    1,353       1,270  
 
           
 
               
Property
               
Property, plant and equipment
    19,673       18,809  
Less accumulated depreciation and depletion
    (7,778 )     (7,401 )
 
           
 
    11,895       11,408  
 
           
 
               
Other Assets
               
Goodwill
    2,037       2,037  
Regulatory assets
    2,803       2,786  
Securitized regulatory assets
    1,066       1,124  
Intangible assets
    87       25  
Notes receivable
    117       87  
Assets from risk management and trading activities
    363       199  
Prepaid pension assets
    162       152  
Other
    129       116  
Noncurrent assets held for sale
          547  
 
           
 
    6,764       7,073  
 
           
 
               
Total Assets
  $ 23,906     $ 23,742  
 
           
See Notes to Consolidated Financial Statements (Unaudited)

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DTE Energy Company
Consolidated Statements of Financial Position (Unaudited)
                 
    June 30     December 31  
(in Millions, Except Shares)   2008     2007  
LIABILITIES AND SHAREHOLDERS’ EQUITY
               
Current Liabilities
               
Accounts payable
  $ 1,173     $ 1,189  
Accrued interest
    118       112  
Dividends payable
    86       87  
Short-term borrowings
    100       1,084  
Gas inventory equalization
    153        
Current portion long-term debt, including capital leases
    590       454  
Liabilities from risk management and trading activities
    818       281  
Deferred gains and reserves
    313       400  
Other
    483       566  
Current liabilities associated with assets held for sale
          48  
 
           
 
    3,834       4,221  
 
           
 
               
Long-Term Debt (net of current portion)
               
Mortgage bonds, notes and other
    5,936       5,576  
Securitization bonds
    996       1,065  
Trust preferred-linked securities
    289       289  
Capital lease obligations
    65       41  
 
           
 
    7,286       6,971  
 
           
 
               
Other Liabilities
               
Deferred income taxes
    1,824       1,824  
Regulatory liabilities
    1,156       1,168  
Asset retirement obligations
    1,310       1,277  
Unamortized investment tax credit
    102       108  
Liabilities from risk management and trading activities
    759       450  
Liabilities from transportation and storage contracts
    119       126  
Accrued pension liability
    68       68  
Accrued postretirement liability
    1,059       1,094  
Deferred gains
    14       15  
Nuclear decommissioning
    127       134  
Other
    286       303  
Noncurrent liabilities associated with assets held for sale
          82  
 
           
 
    6,824       6,649  
 
           
 
               
Commitments and Contingencies (Notes 2, 6 and 9)
               
 
               
Minority Interest
    61       48  
 
           
 
               
Shareholders’ Equity
               
Common stock, without par value, 400,000,000 shares authorized, 163,095,193 and 163,232,095 shares issued and outstanding, respectively
    3,169       3,176  
Retained earnings
    2,862       2,790  
Accumulated other comprehensive loss
    (130 )     (113 )
 
           
 
    5,901       5,853  
 
           
 
               
Total Liabilities and Shareholders’ Equity
  $ 23,906     $ 23,742  
 
           
See Notes to Consolidated Financial Statements (Unaudited)

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DTE Energy Company
Consolidated Statements of Cash Flows (Unaudited)
                 
    Six Months Ended  
    June 30  
(in Millions)   2008     2007  
Operating Activities
               
Net income
  $ 240     $ 519  
Adjustments to reconcile net income to net cash from operating activities:
               
Depreciation, depletion and amortization
    440       467  
Deferred income taxes
    180       (4 )
Gain on sale of non-utility assets
    (128 )     (897 )
Other asset (gains), losses and reserves, net
    12       10  
Gain on sale of interests in synfuel projects
    (15 )     (77 )
Partners’ share of synfuel project (gains) losses
    2       (115 )
Contributions from synfuel partners
    30       101  
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)
    774       994  
 
           
Net cash from operating activities
    1,535       998  
 
           
 
               
Investing Activities
               
Plant and equipment expenditures — utility
    (544 )     (480 )
Plant and equipment expenditures — non-utility
    (110 )     (141 )
Proceeds from sale of interests in synfuel projects
    82       221  
Refunds to synfuel partners
    (96 )     (16 )
Proceeds from sale of non-utility assets
    253       1,258  
Proceeds from sale of other assets, net
    16       11  
Restricted cash for debt redemptions
    54       4  
Proceeds from sale of nuclear decommissioning trust fund assets
    106       124  
Investment in nuclear decommissioning trust funds
    (124 )     (140 )
Other investments
    (89 )     (30 )
 
           
Net cash from (used) for investing activities
    (452 )     811  
 
           
 
               
Financing Activities
               
Issuance of long-term debt
    798        
Redemption of long-term debt
    (154 )     (111 )
Repurchase of long-term debt
    (238 )      
Short-term borrowings, net
    (984 )     (330 )
Repurchase of common stock
    (16 )     (333 )
Dividends on common stock
    (172 )     (187 )
Other
    (6 )     (2 )
 
           
Net cash used for financing activities
    (772 )     (963 )
 
           
 
               
Net Increase in Cash and Cash Equivalents
    311       846  
Cash and Cash Equivalents Reclassified from Assets Held for Sale
    11        
Cash and Cash Equivalents at Beginning of Period
    123       147  
 
           
Cash and Cash Equivalents at End of Period
  $  445     $ 993  
 
           
See Notes to Consolidated Financial Statements (Unaudited)

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DTE Energy Company
Consolidated Statements of Changes in Shareholders’ Equity and
Comprehensive Income (Unaudited)
                                         
                            Accumulated        
                            Other        
    Common Stock     Retained     Comprehensive        
(Dollars in Millions, Shares in Thousands)   Shares     Amount     Earnings     Loss     Total  
 
Balance, December 31, 2007
    163,232     $ 3,176     $ 2,790     $ (113 )   $ 5,853  
 
Net income
                240             240  
Implementation of SFAS No. 157, net of taxes of $2
                4             4  
Dividends declared on common stock
                (172 )           (172 )
Repurchase and retirement of common stock
    (411 )     (16 )                 (16 )
Net change in unrealized losses on derivatives, net of tax
                      (9 )     (9 )
Net change in unrealized losses on investments, net of tax
                      (8 )     (8 )
Stock-based compensation and other
    274       9                   9  
 
Balance, June 30, 2008
    163,095     $ 3,169     $ 2,862     $ (130 )   $ 5,901  
 
The following table displays other comprehensive income for the six-month periods ended June 30:
                 
(in Millions)   2008     2007  
Net income
  $ 240     $ 519  
 
           
Other comprehensive income (loss), net of tax:
               
Benefit obligations, net of taxes of $- and $1, respectively
          2  
 
           
Net unrealized gains (losses) on derivatives:
               
Gains (losses) during the period, net of taxes of $(6) and $(77), respectively
    (11 )     (143 )
Amounts reclassified to income, net of taxes of $1 and $125, respectively
    2       231  
 
           
 
    (9 )     88  
 
           
Net unrealized gains (losses) on investments:
               
Gains (losses) during the period, net of taxes of $(4) and $(2), respectively
    (8 )     (3 )
Amounts reclassified to income, net of taxes of $- and $1, respectively
          2  
 
           
 
    (8 )     (1 )
 
           
Comprehensive income
  $ 223     $ 608  
 
           
See Notes to Consolidated Financial Statements (Unaudited)

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DTE Energy Company
Notes to Consolidated Financial Statements (Unaudited)
NOTE 1 — GENERAL
DTE Energy (the “Company”) is a diversified energy company. It is the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales, distribution and storage services throughout southeastern Michigan. The Company also operates four energy-related non-utility segments with operations throughout the United States.
These Consolidated Financial Statements should be read in conjunction with the Notes to Consolidated Financial Statements included in the 2007 Annual Report on Form 10-K.
The accompanying Consolidated Financial Statements are prepared using accounting principles generally accepted in the United States of America. These accounting principles require us to use estimates and assumptions that impact reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates.
The Consolidated Financial Statements are unaudited, but include all adjustments necessary for a fair presentation of such financial statements. All adjustments are of a normal recurring nature, except as otherwise disclosed in these Consolidated Financial Statements and Notes to Consolidated Financial Statements. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2008.
Certain prior year amounts have been reclassified to reflect current year classifications.
Asset Retirement Obligations
The Company records asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and FIN 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. The Company has a legal retirement obligation for the decommissioning costs for its Fermi 1 and Fermi 2 nuclear plants. To a lesser extent, the Company has legal retirement obligations for the discontinued synthetic fuel operations, gas production facilities, gas gathering facilities and various other operations. The Company has conditional retirement obligations for gas pipeline retirement costs and disposal of asbestos at certain of its power plants. To a lesser extent, the Company has conditional retirement obligations at certain service centers, compressor and gate stations, and disposal costs for PCB contained within transformers and circuit breakers. The Company recognizes such obligations as liabilities at fair market value when they are incurred, which generally is at the time the associated assets are placed in service. Fair value is measured using expected future cash outflows discounted at our credit-adjusted risk-free rate.
For the Company’s regulated operations, timing differences arise in the expense recognition of legal asset retirement costs that the Company is currently recovering in rates. The Company defers such differences under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.
A reconciliation of the asset retirement obligations for the six months ended June 30, 2008 follows:
         
(in Millions)        
Asset retirement obligations at January 1, 2008
  $ 1,293  
Accretion
    42  
Liabilities settled
    (11 )
Revision in estimated cash flows
    (11 )
Transfers from Assets held for sale
    14  
 
     
Asset retirement obligations at June 30, 2008
    1,327  
Less amount included in current liabilities
    (17 )
 
     
 
  $ 1,310  
 
     

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Approximately $1 billion of the asset retirement obligations represent nuclear decommissioning liabilities that are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear power plant.
Intangible Assets
The Company has certain intangible assets relating to non-utility contracts and emission allowances. The Company amortizes intangible assets on a straight-line basis over the expected period of benefit, ranging from 4 to 30 years. The gross carrying amount and accumulated amortization of intangible assets at June 30, 2008 were $101 million and $14 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2007 were $31 million and $6 million, respectively. Amortization expense of intangible assets is estimated to be $5 million annually for the years 2008 through 2012.
Retirement Benefits and Trusteed Assets
The following details the components of net periodic benefit costs for qualified and non-qualified pension benefits and other postretirement benefits:
                                 
                    Other Postretirement  
Three Months Ended June 30   Pension Benefits     Benefits  
(in Millions)   2008     2007     2008     2007  
Service cost
  $ 13     $ 15     $ 16     $ 15  
Interest cost
    47       43       31       31  
Expected return on plan assets
    (65 )     (60 )     (20 )     (16 )
Amortization of:
                               
Net actuarial loss
    8       13       9       16  
Prior service cost
    2       1       (2 )      
Net transition liability
                1        
Special termination benefits
          1              
 
                       
Net periodic benefit cost
  $ 5     $ 13     $ 35     $ 46  
 
                       
                                 
                    Other Postretirement  
Six Months Ended June 30   Pension Benefits     Benefits  
(in Millions)   2008     2007     2008     2007  
Service cost
  $ 28     $ 31     $ 31     $ 30  
Interest cost
    95       88       61       61  
Expected return on plan assets
    (130 )     (120 )     (38 )     (33 )
Amortization of:
                               
Net actuarial loss
    16       28       19       33  
Prior service cost
    3       2       (3 )     (1 )
Net transition liability
                1       2  
Special termination benefits
          5             2  
 
                       
Net periodic benefit cost
  $ 12     $ 34     $ 71     $ 94  
 
                       
Special Termination Benefits in the above table represents costs associated with the Company’s Performance Excellence Process.
The Company expects to contribute $150 million to its qualified pension plans during its fiscal year 2008. No contributions have been made to the plans for the three- and six- month periods ended June 30, 2008.
The Company expects to contribute $5 million to its non-qualified pension plans during its fiscal year 2008. No contributions have been made to the plans for the three- and six- month periods ended June 30, 2008.
The Company expects to contribute $116 million to its postretirement medical and life insurance benefit plans during its fiscal year 2008. No contributions were made during the three-month period ended June 30, 2008. Approximately $40 million of contributions were made to the plans for the six-month period ended June 30, 2008.
Income Taxes
The Company’s effective income tax rate from continuing operations for the three months ended June 30, 2008 was 39% as compared to 41% for the three months ended June 30, 2007, and for the six months ended June 30, 2008 was 37% as compared to 40% for the six months ended June 30, 2007. The 2008 rate is lower than 2007 because in 2007, for interim accounting purposes, tax expense on the Antrim shale gain tax was computed separately as a

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discrete item at its specific tax rate that is higher than the tax rate computed on the remaining results from continuing operations. The 2008 effective tax rate decrease is partially offset by higher state income taxes related to the Michigan Business Tax which was effective January 1, 2008.
The Company has $17 million of unrecognized tax benefits at June 30, 2008 as compared to $14 million of unrecognized tax benefits as December 31, 2007 that, if recognized, would favorably impact its effective tax rate. During the next 12 months, statutes of limitations will expire for the Company’s tax returns in various states. It is reasonably possible that there will be a decrease in unrecognized tax benefits of $7 million within the next 12 months.
Short-Term Credit Arrangements and Borrowings
Detroit Edison had a $200 million short-term financing agreement secured by customer accounts receivable. In June 2008, the agreement was terminated and amounts outstanding under the agreement were repaid.
Stock-Based Compensation
The DTE Energy Stock Incentive Plan (the “Plan”) permits the grant of incentive stock options, non-qualifying stock options, stock awards, performance shares and performance units. Participants in the Plan include the Company’s employees and members of its Board of Directors.
The Company recorded stock-based compensation expense of $18 million and $13 million, with an associated tax benefit of $6 million and $5 million for the three months ended June 30, 2008 and 2007, respectively. The Company recorded stock-based compensation expense of $25 million and $19 million, with an associated tax benefit of $9 million and $7 million for the six months ended June 30, 2008 and 2007, respectively. Compensation cost capitalized in property, plant and equipment was $0.6 million and $1 million during the three months ended June 30, 2008 and 2007, respectively. Compensation cost capitalized in property, plant and equipment was $1 million and $1.5 million during the six months ended June 30, 2008 and 2007, respectively.
Stock Options
The following table summarizes our stock option activity for the six months ended June 30, 2008:
                         
                    (in Millions)  
            Weighted     Aggregate  
    Number of     Average     Intrinsic  
    Options     Exercise Price     Value  
Options outstanding at January 1, 2008
    4,394,809     $ 42.37          
Granted
    811,300     $ 41.77          
Exercised
    (42,230 )   $ 36.56          
Forfeited or expired
    (14,084 )   $ 44.39          
 
                     
Options outstanding at June 30, 2008
    5,149,795     $ 42.31     $ 6  
 
                   
 
                       
Options exercisable at June 30, 2008
    3,861,931     $ 41.98     $ 6  
 
                   
As of June 30, 2008, the weighted average remaining contractual life for the exercisable shares was 4.92 years. As of June 30, 2008, 1,287,864 options were non-vested. During the six months ended June 30, 2008, 605,640 options vested.
The Company determined the fair value for these options at the date of grant using a Black-Scholes based option pricing model and the following assumptions:
                 
    Six Months Ended
    June 30, 2008   June 30, 2007
Risk-free interest rate
    3.05 %     4.61 %
Dividend yield
    5.20 %     4.40 %
Expected volatility
    20.45 %     17.85 %
 
               
Expected life
  6 years   6 years

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The weighted average grant date fair value of options granted during the six months of 2008 was $4.76 per share. The intrinsic value of options exercised for the six months ended June 30, 2008 was $0.3 million. Total option expense recognized was $0.5 million and $0.7 million for the three months ended June 30, 2008 and 2007, respectively, while total option expense recognized was $2.4 million and $2.8 million for the six months ended June 30, 2008 and 2007, respectively.
Stock Awards
The following summarizes stock awards activity for the six months ended June 30, 2008:
                 
            Weighted Average
    Restricted   Grant Date
    Stock   Fair Value
Balance at January 1, 2008
    984,310     $ 47.36  
Grants
    378,400     $ 41.72  
Forfeitures
    (45,499 )   $ 45.12  
Vested
    (235,081 )   $ 45.02  
 
               
Balance at June 30, 2008
    1,082,130     $ 46.00  
 
               
Performance Share Awards
The following summarizes performance share activity for the six months ended June 30, 2008:
         
    Performance Shares
Balance at January 1, 2008
    1,174,153  
Grants
    534,965  
Forfeitures
    (53,251 )
Payouts
    (312,647 )
 
       
 
       
Balance at June 30, 2008
    1,343,220  
 
       
Unrecognized Compensation Cost
As of June 30, 2008, the Company had $54 million of total unrecognized compensation cost related to non-vested stock incentive plan arrangements. These costs are expected to be recognized over a weighted-average period of 1.77 years.

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Consolidated Statement of Cash Flows
The following provides detail of the changes in assets and liabilities that are reported in the Consolidated Statement of Cash Flows, and supplementary cash information:
                 
    Six Months Ended  
    June 30  
(in Millions)   2008     2007  
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
               
Accounts receivable, net
  $ 280     $ 241  
Accrued GCR revenue
    (113 )     (77 )
Inventories
    53       7  
Accrued/prepaid pensions
    (10 )     1  
Accounts payable
    22       131  
Accrued PSCR refund
    95       46  
Exchange gas payable
    (31 )     (16 )
Income taxes payable
    1       136  
General taxes
    4       21  
Risk management and trading activities
    350       213  
Deferred gains from asset sales
    33       (32 )
Gas inventory equalization
    153       145  
Postretirement obligation
    (35 )     10  
Other assets
    58       67  
Other liabilities
    (86 )     101  
 
           
 
  $ 774     $ 994  
 
           
 
               
Supplementary Cash Information
               
Cash paid for interest (net of interest capitalized)
  $ 240     $ 271  
Cash paid for income taxes
  $ 14     $ 109  
NonCash Financing Activities
               
Repurchase of common stock, not settled at balance sheet date
        $ 42  

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In connection with maintaining certain traded risk management positions, the Company may be required to post cash collateral with its clearing agent. As a result, the Company entered into a demand financing agreement for up to $150 million with its clearing agent in lieu of posting additional cash collateral (a non-cash transaction). There was approximately $4 million outstanding under this facility at June 30, 2008 and approximately $13 million outstanding as of December 31, 2007.
Other asset (gains) and losses, reserves and impairments, net
The following items are included in the Other asset (gains) and losses, reserves and impairments, net line in the Consolidated Statement of Operations:
                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
(in Millions)   2008     2007     2008     2007  
Electric utility
  $     $ (1 )   $     $ 6  
Gas utility
                      3  
 
                       
 
          (1 )           9  
 
                       
 
                               
Non-utility:
                               
Power and industrial projects
    16       (1 )     13        
Barnett shale
          9             9  
Other
          2       (1 )     1  
 
                       
 
  $ 16     $ 9     $ 12     $ 19  
 
                       
NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS
Fair Value Accounting
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. It emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Fair value measurement should be determined based on the assumptions that market participants would use in pricing an asset or liability. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Effective January 1, 2008, the Company adopted SFAS No. 157. As permitted by FASB Staff Position FAS No. 157-2, the Company has elected to defer the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009. The cumulative effect adjustment upon adoption of SFAS No. 157 represented a $4 million increase to the January 1, 2008 balance of retained earnings. See also Note 3.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115. This Statement permits an entity to choose to measure many financial instruments and certain other items at fair value. The fair value option established by SFAS No. 159 permits all entities to choose to measure eligible items at fair value at specified election dates. An entity will report in earnings unrealized gains and losses on items, for which the fair value option has been elected, at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. At January 1, 2008, the Company elected not to use the fair value option for financial assets and liabilities held at that date.
Business Combinations
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations, to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish this, SFAS No. 141(R) requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information needed to evaluate and understand the nature and financial effect of the business combination. SFAS No. 141(R) is applied prospectively to business combinations entered into by the Company after January 1, 2009, with earlier adoption

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prohibited. The Company will apply the requirements of SFAS No. 141(R) to business combinations consummated after January 1, 2009.
GAAP Hierarchy
In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. This statement identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements under GAAP. SFAS 162 is effective 60 days following the approval of the Public Company Accounting Oversight Board amendments to AU section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. The Company will adopt SFAS No. 162 once effective, and the adoption is not expected to have a material impact on its consolidated financial statements.
Useful Life of Intangible Assets
In May 2008, the FASB issued FSP FAS 142-3, Determination of the Useful Life of Intangible Assets. This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets. For a recognized intangible asset, an entity shall disclose information that enables users to assess the extent to which the expected future cash flows associated with the asset are affected by the entity’s intent and/or ability to renew or extend the arrangement. This FSP is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. The FSP will not have a material impact on the Company’s consolidated financial statements.
Noncontrolling Interests in Consolidated Financial Statements
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51. This Statement establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 is effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2008. Earlier adoption is prohibited. This Statement shall be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements shall be applied retrospectively for all periods presented. The Company will adopt SFAS No. 160 as of January 1, 2009 and is currently assessing the effects of SFAS No. 160 on its consolidated financial statements.
Disclosures about Derivative Instruments and Hedging Activities
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133. This Statement requires enhanced disclosures about an entity’s derivative and hedging activities. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. Comparative disclosures for earlier periods at initial adoption are encouraged but not required. The Company will adopt SFAS No. 161 on January 1, 2009.
Offsetting Amounts Related to Certain Contracts
In April 2007, the FASB issued FSP FIN 39-1, Amendment of FASB Interpretation No. 39. This FSP permits the Company to offset the fair value of derivative instruments with cash collateral received or paid for those derivative instruments executed with the same counterparty under a master netting arrangement. As a result, the Company is permitted to record one net asset or liability that represents the total net exposure of all derivative positions under a master netting arrangement. The decision to offset derivative positions under master netting arrangements remains an accounting policy choice. The guidance in this FSP is effective for fiscal years beginning after November 15, 2007. It is applied retrospectively by adjusting the financial statements for all periods presented. The Company adopted FSP FIN 39-1 as of January 1, 2008. At adoption, the Company chose to offset the collateral amounts against the fair value of derivative assets and liabilities, reducing both the Company’s total assets and total

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liabilities. The Company retrospectively reclassified certain assets and liabilities on the Consolidated Statement of Financial Position at December 31, 2007 as follows:
                         
    As Previously   FSP FIN 39-1    
(in Millions)   Reported   Adjustments   As Adjusted
Current Assets
                       
Accounts receivable
                       
Collateral held by others
  $ 56     $ (3 )   $ 53  
Other
    448       13       461  
Assets from risk management and trading activities
    195       (14 )     181  
Other Assets
                       
Assets from risk management and trading activities
    207       (8 )     199  
Current Liabilities
                       
Accounts payable
    1,198       (9 )     1,189  
Liabilities from risk management and trading activities
    282       (1 )     281  
Other Liabilities
                       
Liabilities from risk management and trading activities
    452       (2 )     450  
NOTE 3 — FAIR VALUE
Effective January 1, 2008, the Company adopted SFAS No. 157. This Statement defines fair value, establishes a framework for measuring fair value and expands the disclosures about fair value measurements. The Company has elected the option to defer the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009.
SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Company makes certain assumptions that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.
SFAS No. 157 establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. SFAS No. 157 requires that assets and liabilities be classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The Company classifies fair value balances based on the fair value hierarchy defined by SFAS No. 157 as follows:
    Level 1 — Consists of unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access as of the reporting date.
 
    Level 2 — Consists of inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
 
    Level 3 — Consists of unobservable inputs for assets or liabilities whose fair value is estimated based on internally developed models or methodologies using inputs that are generally less readily observable and supported by little, if any, market activity at the measurement date. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

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The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2008:
                                         
                            Netting     Net Balance at  
(in Millions)   Level 1     Level 2     Level 3     Adjustments(2)     June 30, 2008  
Assets:
                                       
Nuclear decommissioning trusts
  $ 493     $ 301     $     $     $ 794  
Employee benefit trust investments (1)
    20       59                   79  
Derivative assets
    584       4,041       1,508       (5,256 )     877  
 
                             
Total
  $ 1,097     $ 4,401     $ 1,508     $ (5,256 )   $ 1,750  
 
                             
Liabilities:
                                       
Deferred compensation
  $     $ (19 )   $     $     $ (19 )
Derivative liabilities
    (610 )     (3,488 )     (2,348 )     4,869       (1,577 )
 
                             
Total
  $ (610 )   $ (3,507 )   $ (2,348 )   $ 4,869     $ (1,596 )
 
                             
Net Assets (Liabilities) at June 30, 2008
  $ 487     $ 894     $ (840 )   $ (387 )   $ 154  
 
                             
 
(1)   Excludes cash surrender value of life insurance investments.
 
(2)   Amounts represent the impact of master netting agreements that allow the Company to net gain and loss positions and cash collateral held or placed with the same counterparties.
The following table presents the fair value reconciliation of Level 3 derivative assets and liabilities measured at fair value on a recurring basis for the six months ended June 30, 2008:
         
(in Millions)   Derivatives  
Liability balance as of January 1, 2008 (1)
  $ (366 )
Changes in fair value recorded in income
    (360 )
Changes in fair value recorded in other comprehensive income
    (17 )
Purchases, issuances and settlements
    (103 )
Transfers in/out of Level 3
    6  
 
     
Liability balance as of June 30, 2008
  $ (840 )
 
     
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at June 30, 2008
  $ (360 )
 
     
 
(1)   Balance as of January 1, 2008 includes a cumulative effect adjustment which represents an increase to beginning retained earnings related to Level 3 derivatives upon adoption of SFAS No. 157.
Net losses of $360 million related to Level 3 derivative assets and liabilities are reported in Operating Revenues for the six months ended June 30, 2008 consistent with the Company’s accounting policy. Net gains of $494 million related to Level 1 and Level 2 derivative assets and liabilities, and the impact of netting, are also reported in Operating Revenues for the six months ended June 30, 2008. Transfers in and/or out of level 3 represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.
SFAS No. 157 provides for limited retrospective application, the net of which is recorded as an adjustment to beginning retained earnings in the period of adoption. As a result, the Company recorded a cumulative effect adjustment of $4 million, net of taxes, as an increase to beginning retained earnings as of January 1, 2008.
Nuclear Decommissioning Funds
The trust fund investments have been established to satisfy Detroit Edison’s nuclear decommissioning obligations. The nuclear decommissioning trust fund investments hold debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued using quoted prices in actively traded markets. Non-exchange traded fixed income securities are valued based upon quotations available from brokers or pricing services.
Employee Benefit Trust Investments
The employee benefit trust investments are invested in commingled funds and institutional mutual funds holding equity or fixed income securities. The commingled funds and institutional mutual funds which hold exchange-traded equity securities are valued using quoted prices in actively traded markets. Non-exchange-traded fixed income securities are valued based upon quotations available from brokers or pricing services.

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Deferred Compensation Liabilities
Deferred compensation plans allow eligible participants to defer a portion of their compensation. The participant is able to designate the investment of the deferred compensation to investments available under the 401(k) plan offered by the Company, although the Company does not actually purchase the investments. The deferred compensation liability is determined based upon the fair values of the mutual funds and equity securities designated in each participant’s account.
Derivative Assets and Liabilities
Derivative assets and liabilities are comprised of physical and financial derivative contracts, including futures, forwards, options and swaps that are both exchange-traded and over-the-counter traded contracts. Various inputs are used to value derivatives depending on the type of contract and availability of market data. Exchange-traded derivative contracts are valued using quoted prices in active markets. Other derivatives contracts are valued based upon a variety of inputs including commodity market prices, interest rates, credit ratings, default rates, market-based seasonality and basis differential factors. Mathematical valuation models are used for derivatives for which external market data is not readily observable, such as contracts which extend beyond the actively traded reporting period. Derivative instruments are principally used in the Company’s Energy Trading segment.
NOTE 4 — DISPOSALS AND DISCONTINUED OPERATIONS
Sale of Antrim Shale Gas Exploration and Production Business
In June 2007, the Company sold its Antrim shale gas exploration and production business (Antrim) for gross proceeds of approximately $1.3 billion and recognized a pre-tax gain of $900 million ($580 million after-tax) during 2007. Prior to the sale, the operating results of Antrim were reflected in the Unconventional Gas Production segment.
The Antrim business is not presented as a discontinued operation due to continuation of cash flows related to the sale of a portion of Antrim’s natural gas production to Energy Trading under the terms of natural gas sales contracts that expire in 2010 and 2012. These continuing cash flows, while not significant to DTE Energy, are significant to Antrim and therefore meet the definition of continuing cash flows as described in EITF 03-13, Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations.
Plan to Sell Interest in Certain Power and Industrial Projects
During the third quarter of 2007, the Company announced its plans to sell a 50% interest in a portfolio of select Power and Industrial Projects. As a result, the assets and liabilities of the Projects were classified as held for sale at that time and the Company ceased recording depreciation and amortization expense related to these assets. During the second quarter of 2008, the United States asset sale market has weakened and challenges in the debt market have persisted. Additionally, the performance of the portfolio of select Power and Industrial Projects has improved. As a result of these developments, the Company’s work on this planned monetization has been discontinued. As of June 30, 2008, the assets and liabilities of the Projects were no longer classified as held for sale. Depreciation and amortization resumed in June 2008 when the assets were reclassified as held and used. During the three- and six-month periods ended June 30, 2008, the Company recorded a loss of $19 million related to the valuation adjustment for the cumulative depreciation and amortization not recorded during the held for sale period. The Consolidated Statement of Financial Position includes $28 million of minority interests in the Projects classified as held for sale as of December 31, 2007.
The following table presents the major classes of assets and liabilities of the Projects classified as held for sale at December 31, 2007:
         
    December 31,  
(in Millions)   2007  
Cash and cash equivalents
  $ 11  
Accounts receivable (less allowance for doubtful accounts of $4)
    65  
Inventories
    4  
Other current assets
    3  
 
     
Total current assets held for sale
    83  
 
     

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    December 31,  
(in Millions)   2007  
Investments
    55  
Property, plant and equipment, net of accumulated depreciation of $183
    285  
Intangible assets
    38  
Long-term notes receivable
    46  
Other noncurrent assets
    1  
 
     
Total noncurrent assets held for sale
    425  
 
     
 
       
Total assets held for sale
  $ 508  
 
     
 
       
Accounts payable
  $ 38  
Other current liabilities
    10  
 
     
Total current liabilities associated with assets held for sale
    48  
 
     
 
       
Long-term debt (including capital lease obligations of $31)
    53  
Asset retirement obligations
    16  
Other liabilities
    13  
 
     
Total noncurrent liabilities associated with assets held for sale
    82  
 
     
 
       
Total liabilities related to assets held for sale
  $ 130  
 
     
Sale of Interest in Barnett Shale Properties
In 2008, the Company sold a portion of its Barnett shale properties for gross proceeds of approximately $260 million. As of December 31, 2007, property, plant and equipment of approximately $122 million, net of approximately $14 million of accumulated depreciation and depletion, was classified as held for sale. The Company recognized a gain of $128 million ($81 million after-tax) on the sale during 2008.
Synthetic Fuel Business
The Company discontinued the operations of its synthetic fuel production facilities throughout the United States as of December 31, 2007. Synfuel plants chemically changed coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits were provided for the production and sale of solid synthetic fuel produced from coal and were available through December 31, 2007. The synthetic fuel plants generated operating losses that were substantially offset by production tax credits.
The Company has reported the activity of the Synthetic Fuel business as a discontinued operation. The following amounts exclude general corporate overhead costs.
                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
(in Millions)   2008     2007     2008     2007  
Operating Revenues
  $     $ 262     $ 7     $ 529  
Operation and Maintenance
    1       314       9       638  
Depreciation, Depletion and Amortization
    (1 )     2       (2 )     3  
Taxes Other Than Income
    (1 )     4       (1 )     8  
Asset (Gains), Losses and Reserves, Net
    1       (41 )     (15 )     (77 )
 
                       
Operating Income (Loss)
          (17 )     16       (43 )
Other (Income) and Deductions
    (1 )     (2 )     (2 )     (6 )
Minority Interest
    2       (56 )     2       (115 )
Income Taxes
                               
Provision (Benefit)
    (1 )     14       5       27  
Production Tax Credits
          (10 )     (1 )     (24 )
 
                       
 
    (1 )     4       4       3  
 
                       
Net Income
  $     $ 37     $ 12     $ 75  
 
                       

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NOTE 5 — RESTRUCTURING
In 2005, the Company initiated a company-wide review of its operations called the Performance Excellence Process and began a series of focused improvement initiatives within its Electric and Gas Utilities, and the related corporate support functions. This process continued as of June 30, 2008.
The Company incurred costs to achieve (CTA) restructuring expense for employee severance and other costs. Other costs include project management and consultant support. Pursuant to MPSC authorization, beginning in the third quarter of 2006, Detroit Edison deferred approximately $102 million of CTA in 2006. During 2007, Detroit Edison deferred CTA costs of $54 million. Detroit Edison began amortizing deferred 2006 costs in 2007 and 2007 deferred costs in 2008 as the recovery of these costs was provided for by the MPSC. Amortization of prior year deferred CTA costs was $4 million and $2 million for the three months ended June 30, 2008 and 2007, respectively, and $8 million and $5 million for the six months ended June 30, 2008 and 2007, respectively. Detroit Edison deferred approximately $7 million and $8 million of CTA for the three months ended June 30, 2008 and 2007, respectively, and approximately $11 million and $21 million of CTA for the six months ended June 30, 2008 and 2007, respectively. MichCon cannot defer CTA costs because a recovery mechanism has not been established. MichCon plans to seek a recovery mechanism in its next rate case which is expected to be filed in 2009. See Note 6.
Amounts expensed are recorded in Operation and maintenance on the Consolidated Statements of Operations. Deferred amounts are recorded in the Regulatory assets line on the Consolidated Statements of Financial Position. Costs incurred for the three- and six-month periods ended June 30, 2008 and 2007 are as follows:
                                                 
Three Months Ended June 30   Employee Severance Costs     Other Costs     Total Cost  
(in Millions)   2008     2007     2008     2007     2008     2007  
Costs incurred:
                                               
Electric Utility
  $     $ 3     $ 8     $ 7     $ 8     $ 10  
Gas Utility
                2       1       2       1  
Other
          1                         1  
 
                                   
Total costs
          4       10       8       10       12  
Less amounts deferred or capitalized:
                                               
Electric Utility
          3       8       7       8       10  
 
                                   
Amount expensed
  $     $ 1     $ 2     $ 1     $ 2     $ 2  
 
                                   
                                                 
Six Months Ended June 30   Employee Severance Costs     Other Costs     Total Cost  
(in Millions)   2008     2007     2008     2007     2008     2007  
Costs incurred:
                                               
Electric Utility
  $     $ 11     $ 12     $ 14     $ 12     $ 25  
Gas Utility
          2       3       1       3       3  
Other
          1       1             1       1  
 
                                   
Total costs
          14       16       15       16       29  
Less amounts deferred or capitalized:
                                               
Electric Utility
          11       12       14       12       25  
 
                                   
Amount expensed
  $     $ 3     $ 4     $ 1     $ 4     $ 4  
 
                                   
NOTE 6 — REGULATORY MATTERS
Regulation
Detroit Edison and MichCon are subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to rates, and recovery of certain costs. These costs include the costs of generating facilities, regulatory assets, conditions of service, accounting, and operating-related matters. Detroit Edison is also regulated by the FERC with respect to financing authorization and wholesale electric activities.
MPSC Show-Cause Order
In March 2006, the MPSC issued an order directing Detroit Edison to show cause by June 1, 2006 why its rates should not be reduced in 2007. Subsequently, Detroit Edison filed its response to this order and the MPSC issued an

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order approving a settlement agreement in this proceeding on August 31, 2006. The order provided for an annualized rate reduction of $53 million for 2006, effective September 5, 2006. Beginning January 1, 2007, and continuing until April 13, 2008, one year from the filing of the general rate case on April 13, 2007, rates were reduced by an additional $26 million, for a total reduction of $79 million annually. The revenue reduction is net of the recovery of the amortization of the costs associated with the implementation of the Performance Excellence Process. The settlement agreement provided for some level of realignment of the existing rate structure by allocating a larger percentage share of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.
As part of the settlement agreement, a Choice Incentive Mechanism (CIM) was established with a base level of electric choice sales set at 3,400 GWh. The CIM prescribes regulatory treatment of changes in non-fuel revenue attributed to increases or decreases in electric Customer Choice sales. If electric Customer Choice sales exceed 3,600 GWh, Detroit Edison will be able to recover 90% of its reduction in non-fuel revenue from full service customers, up to $71 million. If electric Customer Choice sales fall below 3,200 GWh, Detroit Edison will credit 100% of the increase in non-fuel revenue to the unrecovered regulatory asset balance. In March 2008, Detroit Edison filed a reconciliation of its CIM for the year 2007. Detroit Edison’s annual Electric Choice sales for 2007 were 2,239 GWh which was below the base level of sales of 3,200 GWh. Accordingly, the Company used the resulting additional non-fuel revenue to reduce unrecovered regulatory asset balances related to the Regulatory Asset Recovery Surcharge (RARS) mechanism. This reconciliation did not result in any rate increase.
2007 Electric Rate Case Filing
Pursuant to the February 2006 MPSC order in Detroit Edison’s rate restructuring case and the August 2006 MPSC order in the settlement of the show cause case, Detroit Edison filed a general rate case on April 13, 2007 based on a 2006 historical test year. The filing with the MPSC requested a $123 million, or 2.9%, average increase in Detroit Edison’s annual revenue requirement for 2008.
The requested $123 million increase in revenues is required to recover significant environmental compliance costs and inflationary increases, partially offset by net savings associated with the Performance Excellence Process. The filing was based on a return on equity of 11.25% on an expected 50% capital and 50% debt capital structure by the end of 2008.
In addition, Detroit Edison’s filing made, among other requests, the following proposals:
    Make progress toward correcting the existing rate structure to more accurately reflect the actual cost of providing service to business customers;
 
    Equalize distribution rates between Detroit Edison full service and Customer Choice customers;
 
    Re-establish with modification the CIM originally established in the Detroit Edison 2006 show cause filing. The CIM reconciles changes related to customers moving between Detroit Edison full service and electric Customer Choice;
 
    Terminate the Pension Equalization Mechanism;
 
    Establish an emission allowance pre-purchase plan to ensure that adequate emission allowances will be available for environmental compliance; and
 
    Establish a methodology for recovery of the costs associated with preparation of an application for a new nuclear generation facility.
Also in the filing, in connection with Michigan’s 21st Century Energy Plan, Detroit Edison reinstated a long-term integrated resource planning (IRP) process with the purpose of developing the least overall cost plan to serve customers’ generation needs over the next 20 years. Based on the IRP, new base load capacity may be required for Detroit Edison. To protect tax credits available under federal law, Detroit Edison determined it would be prudent to initiate the application process for a new nuclear unit. Detroit Edison has not made a decision to build a new nuclear unit; however, it has elected to preserve its option to build at some point in the future by beginning the complex

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nuclear licensing process in 2007. Additionally, beginning the licensing process at the present time positions Detroit Edison to potentially take advantage of tax incentives of up to $320 million derived from provisions in the 2005 Federal Energy Policy Act, which will benefit customers. To qualify for these tax credits, a combined operating license application for construction and operation of an advanced nuclear generating plant must be docketed by the Nuclear Regulatory Commission no later than December 31, 2008. Preparation and approval of a combined operating license can take up to 4 years and is estimated to cost at least $60 million. Costs of $16 million related to preparing the combined licensing application have been deferred and included in Other assets as of June 30, 2008.
On August 31, 2007, Detroit Edison filed a supplement to its April 2007 rate case filing. A July 2007 decision by the State of Michigan Court of Appeals remanded back to the MPSC the November 2004 order in a prior Detroit Edison rate case that denied recovery of merger control premium costs. The supplemental filing addressed recovery of approximately $61 million related to the merger control premium. The filing also included the impact of the July 2007 enactment of the MBT and other adjustments. The net impact of the supplemental filing resulted in an approximately $76 million average increase in Detroit Edison’s annual revenue requirement for 2008.
On February 20, 2008, Detroit Edison filed an update to its April 2007 rate case filing. The update reflected the use of 2009 as the projected test year and included a revised 2009 load forecast; 2009 revised estimates on environmental and advanced metering infrastructure capital expenditures; and adjustments to the calculation of the MBT. The update also included the August 2007 supplemental filing adjustments for the merger control premium, the new MBT and environmental operating and maintenance adjustments. The net impact of the updated filing resulted in an approximately $85 million average increase in Detroit Edison’s annual revenue requirement for 2009. The total filing requested a $284 million increase in Detroit Edison’s annual revenue for 2009. An MPSC order related to this filing is expected by early 2009.
Regulatory Accounting Treatment for Performance Excellence Process
In May 2006, Detroit Edison and MichCon filed applications with the MPSC to allow deferral of costs associated with the implementation of the Performance Excellence Process, a Company-wide cost-savings and performance improvement program. Detroit Edison and MichCon sought MPSC authorization to defer and amortize Performance Excellence Process implementation costs for accounting purposes to match the expected savings from the Performance Excellence Process program with the related CTA.
The Performance Excellence Process continued as of June 30, 2008. In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison and MichCon, commencing in 2006, to defer the incremental CTA, subject to the MPSC establishing a recovery mechanism. Further, the order provided for Detroit Edison and MichCon to amortize the CTA deferrals over a 10-year period beginning with the year subsequent to the year the CTA was deferred. Detroit Edison deferred approximately $102 million and $54 million of CTA in 2006 and 2007, respectively, as a regulatory asset and began amortizing deferred costs in 2007 as the recovery of these costs was provided for by the MPSC in the order approving the settlement in the show cause proceeding. Amortization of prior years deferred CTA costs was $4 million and $2 million for the three months ended June 30, 2008 and 2007, respectively, and $8 million and $5 million for the six months ended June 30, 2008 and 2007, respectively. Detroit Edison deferred approximately $7 million and $8 million of CTA for the three months ended June 30, 2008 and 2007, respectively, and approximately $11 million and $21 million of CTA for the six months ended June 30, 2008 and 2007, respectively. MichCon cannot defer CTA costs at this time because a regulatory recovery mechanism has not been established by the MPSC. MichCon plans to seek a recovery mechanism in its next rate case which is expected to be filed in 2009.
Accounting for Costs Related to Enterprise Business Systems (EBS)
In July 2004, Detroit Edison filed an accounting application with the MPSC requesting authority to capitalize and amortize costs related to EBS, consisting of computer equipment, software and development costs, as well as related training, maintenance and overhead costs. In April 2005, the MPSC approved a settlement agreement providing for the deferral of up to $60 million of certain EBS costs, which would otherwise be expensed, as a regulatory asset for future rate recovery starting January 1, 2006. At June 30, 2008, approximately $26 million of EBS costs have been deferred as a regulatory asset. EBS costs recorded as plant assets are being amortized over a 15-year period, pursuant to MPSC authorization.

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Fermi 2 Enhanced Security Costs Settlement
The Customer Choice and Electricity Reliability Act, as amended in 2003, allows for the recovery of reasonable and prudent costs of new and enhanced security measures required by state or federal law, including providing for reasonable security from an act of terrorism. In December 2006, Detroit Edison filed an application with the MPSC for recovery of $11.4 million of Fermi 2 Enhanced Security Costs (ESC), discounted back to September 11, 2001 plus carrying costs from that date. In April 2007, the MPSC approved a settlement agreement that authorizes Detroit Edison to recover Fermi 2 ESC incurred during the period of September 11, 2001 through December 31, 2005. The settlement defined Detroit Edison’s ESC, discounted back to September 11, 2001, as $9.1 million plus carrying charges. A total of $13 million, including carrying charges, has been deferred as a regulatory asset. Detroit Edison is authorized to incorporate into its rates an enhanced security factor over a period not to exceed five years. Amortization expense related to this regulatory asset was approximately $1 million and $2 million for the three- and six-month periods ended June 30, 2008, respectively.
Reconciliation of Regulatory Asset Recovery Surcharge
In December 2006, Detroit Edison filed a reconciliation of costs underlying its existing RARS. This true-up filing was made to maximize the remaining time for recovery of significant cost increases prior to expiration of the RARS 5-year recovery limit under PA 141. Detroit Edison requested a reconciliation of the regulatory asset surcharge to ensure proper recovery by the end of the 5-year period of: (1) Clean Air Act Expenditures, (2) Capital in Excess of Base Depreciation, (3) MISO Costs and (4) the regulatory liability for the 1997 Storm Charge. In July 2007, the MPSC approved a negotiated RARS deficiency settlement that resulted in a $10 million write-down of RARS-related costs in 2007. As discussed above, the CIM in the MPSC Show-Cause Order will reduce the regulatory asset. Detroit Edison had no CIM reductions for the three months ended June 30, 2008 due to the expiration of the CIM in April 2008. Approximately $5 million was credited to the unrecovered regulatory asset balance during the three months ended June 30, 2007. Approximately $11 million and $7 million was credited to the unrecovered regulatory asset balance during the six months ended June 30, 2008 and 2007, respectively.
Power Supply Costs Recovery Proceedings
2005 Plan Year — In March 2006, Detroit Edison filed its 2005 PSCR reconciliation that sought approval for recovery of an under-recovery of approximately $144 million at December 31, 2005 from its commercial and industrial customers. The filing included a motion for entry of an order to implement immediately a reconciliation surcharge of 4.96 mills per kWh on the bills of its commercial and industrial customers. The under-collected PSCR expense allocated to residential customers could not be recovered due to the PA 141 rate cap for residential customers, which expired January 1, 2006. In addition to the 2005 PSCR plan year reconciliation, the filing included a reconciliation for the Pension Equalization Mechanism (PEM) for the periods from November 24, 2004 through December 31, 2004 and from January 1, 2005 through December 31, 2005. The PEM reconciliation seeks to allocate and refund approximately $12 million to customers based on their contributions to pension expense during the subject periods. In September 2006, the MPSC ordered the Company to roll the entire 2004 PSCR over-collection amount to its 2005 PSCR Reconciliation. An order was issued on May 22, 2007 approving a 2005 PSCR under-collection amount of $94 million and the recovery of this amount through a surcharge for 12 months beginning in June 2007. In addition, the order approved Detroit Edison’s proposed PEM reconciliation that was refunded to customers on a bills-rendered basis during June 2007. The 2005 under-collection surcharge was terminated in May 2008. The surcharge will be reconciled in the Company’s 2008 PSCR reconciliation.
2006 Plan Year — In March 2007, Detroit Edison filed its 2006 PSCR reconciliation that sought approval for recovery of an under-collection of approximately $51 million. Included in the 2006 PSCR reconciliation filing was the Company’s PEM reconciliation that reflects a $21 million over-collection which is subject to refund to customers. An MPSC order was issued on April 22, 2008 approving the 2006 PSCR under-collection amount of $51 million and the recovery of this amount as part of the 2007 PSCR factor. In addition, the order approved Detroit Edison’s PEM reconciliation and authorized the Company to refund the $22 million over-recovery, including interest, to customers in May 2008. The 2006 PEM refund was included in May 2008 customer bills. The refund will be reconciled in the Company’s 2008 PEM reconciliation.

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2007 Plan Year — In September 2006, Detroit Edison filed its 2007 PSCR plan case seeking approval of a levelized PSCR factor of 6.98 mills per kWh above the amount included in base rates for all PSCR customers. The Company’s PSCR plan filing included $130 million for the recovery of its projected 2006 PSCR under-collection, bringing the total requested PSCR factor to 9.73 mills/kWh. The Company’s application included a request for an early hearing and temporary order granting such ratemaking authority. The Company’s 2007 PSCR plan included fuel and power supply costs, including NOx and SO2 emission allowance costs, transmission costs and MISO costs. The Company filed supplemental testimony and briefs in December 2006 supporting its updated request to include approximately $81 million for the recovery of its projected 2006 PSCR under-collection. The MPSC issued a temporary order in December 2006 approving the Company’s request. In addition, Detroit Edison was granted the authority to include all PSCR over/(under) collections in future PSCR plans, thereby reducing the time between refund or recovery of PSCR reconciliation amounts. The Company began to collect its 2007 power supply costs, including the 2006 rollover amount, through a PSCR factor of 8.69 mills/kWh on January 1, 2007. The Company reduced the PSCR factor to 6.69 mills/kWh on July 1, 2007 based on the updated 2007 plan year projections and increased the PSCR factor to 8.69 mills/kWh on December 1, 2007. In August 2007, the MPSC approved Detroit Edison’s 2007 PSCR plan case and authorized the Company to charge a maximum power supply cost recovery factor of 8.69 mills/kWh in 2007. The Company filed its 2007 PSCR reconciliation case in March 2008. The filing requests recovery of a $44 million PSCR under-collection through its 2008 PSCR plan. Included in the 2007 PSCR reconciliation filing was the Company’s 2007 PEM reconciliation that reflects a $21 million over-collection, including interest and prior year refunds. The Company expects an order in this proceeding in the second quarter of 2009.
2008 Plan Year — In September 2007, Detroit Edison filed its 2008 PSCR plan case seeking approval of a levelized PSCR factor of 9.23 mills/kWh above the amount included in base rates for all PSCR customers. The Company is supporting a total 2008 power supply expense forecast of $1.3 billion that includes $1 million for the recovery of its projected 2007 PSCR under-collection. The Company’s PSCR Plan will allow the Company to recover its reasonably and prudently incurred power supply expense including fuel costs, purchased and net interchange power costs, NOx and SO2 emission allowance costs, transmission costs and MISO costs. Also included in the filing was a request for approval of the Company’s emission compliance strategy which included pre-purchases of emission allowances as well as a request for pre-approval of a contract for capacity and energy associated with a renewable wind energy project. On January 31, 2008, Detroit Edison filed a revised PSCR plan case seeking approval of a levelized PSCR factor of 11.22 mills/kWh above the amount included in base rates for all PSCR customers. The revised filing supports a 2008 power supply expense forecast of $1.4 billion and includes $43 million for the recovery of a projected 2007 PSCR under-collection. In March 2008, the MPSC ordered that Detroit Edison shall not self-implement the 11.22 mills/kWh power supply cost recovery factor proposed in its January 2008 filing. Detroit Edison filed a renewed motion for a temporary order to implement the 11.22 mills/kWh factor in June 2008. On July 29, 2008, the MPSC issued a temporary order approving Detroit Edison’s request to increase the PSCR factor to 11.22 mills/kWh. The Company expects a final MPSC order in this proceeding in the fourth quarter of 2008.
Uncollectible Expense True-Up Mechanism (UETM) and Report of Safety and Training-Related Expenditures
2005 UETM — In March 2006, MichCon filed an application with the MPSC for approval of its UETM for 2005. This was the first filing MichCon made under the UETM, which was approved by the MPSC in April 2005 as part of MichCon’s last general rate case. MichCon’s 2005 base rates included $37 million for anticipated uncollectible expenses. Actual 2005 uncollectible expenses totaled $60 million. The true-up mechanism allowed MichCon to recover 90% of uncollectibles that exceeded the $37 million base. Under the formula prescribed by the MPSC, MichCon recorded an under-recovery of approximately $11 million for uncollectible expenses from May 2005 (when the mechanism took effect) through the end of 2005. In December 2006, the MPSC issued an order authorizing MichCon to implement the UETM monthly surcharge for service rendered on and after January 1, 2007.
As part of the March 2006 application with the MPSC, MichCon filed a review of its 2005 annual safety and training-related expenditures. MichCon reported that actual safety and training-related expenditures for the initial period exceeded the pro-rata amounts included in base rates and, based on the under-recovered position, recommended no refund at that time. In the December 2006 order, the MPSC also approved MichCon’s 2005 safety and training report.

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2006 UETM — In March 2007, MichCon filed an application with the MPSC for approval of its UETM for 2006 requesting $33 million of under-recovery plus applicable carrying costs of $3 million. The March 2007 application included a report of MichCon’s 2006 annual safety and training-related expenditures, which showed a $2 million over-recovery. In August 2007, MichCon filed revised exhibits reflecting an agreement with the MPSC Staff to net the $2 million over-recovery and associated interest related to the 2006 safety and training-related expenditures against the 2006 UETM under-recovery. An MPSC order was issued in December 2007 approving the collection of $33 million requested in the August 2007 revised filing. MichCon was authorized to implement the new UETM monthly surcharge for service rendered on and after January 1, 2008.
2007 UETM – In March 2008, MichCon filed an application with the MPSC for approval of its UETM for 2007 requesting approximately $34 million. This total includes $33 million of costs related to 2007 uncollectible expense and associated carrying charges and $1 million of under-collections for the 2005 UETM. The March 2008 application included a report of MichCon’s 2007 annual safety and training-related expenses, which showed no refund was necessary because actual expenditures exceeded the amount included in base rates. MichCon anticipates the MPSC will issue an order authorizing MichCon to implement the monthly UETM surcharge proposed in this filing for service rendered on and after January 1, 2009.
Gas Cost Recovery Proceedings
2005-2006 Plan Year — In June 2006, MichCon filed its GCR reconciliation for the 2005-2006 GCR year. The filing supported a total over-recovery, including interest through March 2006, of $13 million. MPSC Staff and other interveners filed testimony regarding the reconciliation in which they recommended disallowances related to MichCon’s implementation of its dollar cost averaging fixed price program. In January 2007, MichCon filed testimony rebutting these recommendations. In December 2007, the MPSC issued an order adopting the adjustments proposed by the MPSC Staff, resulting in an $8 million disallowance. Expense related to the disallowance was recorded in 2007. The MPSC authorized MichCon to roll a net over-recovery, inclusive of interest, of $20 million into its 2006-2007 GCR reconciliation. In December 2007, MichCon filed an appeal of the case with the Michigan Court of Appeals. MichCon is currently unable to predict the outcome of the appeal.
2006-2007 Plan Year — In June 2007, MichCon filed its GCR reconciliation for the 2006-2007 GCR year. The filing supported a total under-recovery, including interest through March 2007, of $18 million. In March 2008, the parties reached a settlement agreement that allowed for full recovery of MichCon’s GCR costs during the 2006-2007 GCR year. The settlement reflected the $20 million net over-recovery required by the MPSC’s order in its 2005-2006 GCR reconciliation. The under-recovery including interest through March 2007 agreed to under the settlement is $9 million and will be included in the 2007-2008 GCR reconciliation. An MPSC order was issued on April 22, 2008 approving the settlement.
2007-2008 Plan Year / Base Gas Sale Consolidated — In August 2006, MichCon filed an application with the MPSC requesting permission to sell base gas that would become accessible with storage facilities upgrades. In December 2006, MichCon filed its 2007-2008 GCR plan case proposing a maximum GCR factor of $8.49 per Mcf. In August 2007, a settlement agreement in this proceeding was reached by all intervening parties that provided for a sharing with customers of the proceeds from the sale of base gas. In addition, the agreement provided for a rate case filing moratorium until January 1, 2009, unless certain unanticipated changes occur that impact income by more than $5 million. The settlement agreement was approved by the MPSC in August 2007. MichCon’s gas storage enhancement projects, the main subject of the aforementioned settlement, have enabled 17 billion cubic feet (Bcf) of gas to become available for cycling. Under the settlement terms, MichCon delivered 13.4 Bcf of this gas to its customers through 2007 at a savings to market-priced supplies of approximately $54 million. This settlement also provided for MichCon to retain the proceeds from the sale of 3.6 Bcf of gas, which MichCon expects to sell through 2009. During 2007, MichCon sold 0.75 Bcf of base gas and recognized a pre-tax gain of $5 million. There were no sales of base gas in the first six months of 2008. By enabling MichCon to retain the profit from the sale of this gas, the settlement provides MichCon with the opportunity to earn an 11% return on equity with no customer rate increase for a period of five years from 2005 to 2010. In June 2008, MichCon filed its GCR reconciliation for the 2007-2008 GCR year. The filing supported a total under-recovery, including interest through March 2008, of $10 million.
2008-2009 Plan Year — In December 2007, MichCon filed its GCR plan case for the 2008-2009 GCR Plan year. MichCon filed for a maximum GCR factor of $8.36 per Mcf, adjustable by a contingent mechanism. In June 2008, MichCon made an informational filing documenting the increase in market prices for gas since its December 2007 filing and calculating its new maximum factor of $10.76 per Mcf based on its contingent mechanism. On July 16,

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2008, all parties agreed to settle all but one of the issues in this case. The partial settlement includes the establishment of a new maximum base GCR factor of $11.36 per Mcf that will not be subject to adjustment by contingent GCR factors for the remainder of the 2008-2009 GCR plan year. An MPSC order approving the partial settlement agreement is expected in 2008. The MPSC’s final order on the remaining issue subject to litigation in this case is expected in 2008.
2009 Proposed Native Base Gas Sale — In July 2008, MichCon filed an application with the MPSC requesting permission to sell an additional 4 Bcf of base gas that will become available for sale as a result of better than expected operations at its storage fields. MichCon proposed to sell 1.3 Bcf of the base gas to GCR customers during the 2009-2010 GCR period at cost and to sell the remaining 2.7 Bcf to non-system supply customers in 2009 at market prices. MichCon requested that the MPSC treat the proceeds from the sale of the 2.7 Bcf of base gas to non-system supply customers as a one-time increase in MichCon’s net income and not include the proceeds in the calculation of MichCon’s revenue requirements in future rate cases.
Other
In July 2007, the State of Michigan Court of Appeals published its decision with respect to an appeal by Detroit Edison and others of certain provisions of a November 2004 MPSC order, including reversing the MPSC’s denial of recovery of merger control premium costs. In its published decision, the Court of Appeals held that Detroit Edison is entitled to recover its allocated share of the merger control premium and remanded this matter to the MPSC for further proceedings to establish the precise amount and timing of this recovery. Detroit Edison has filed a supplement to its April 2007 rate case to address the recovery of the merger control premium costs. Other parties have filed requests for leave to appeal to the Michigan Supreme Court from the Court of Appeals decision. In September 2007, the Court of Appeals remanded to the MPSC, for reconsideration, the MichCon recovery of merger control premium costs. The Company is unable to predict the financial or other outcome of any legal or regulatory proceeding at this time.
The Company is unable to predict the outcome of the regulatory matters discussed herein. Resolution of these matters is dependent upon future MPSC orders and appeals, which may materially impact the financial position, results of operations and cash flows of the Company.
NOTE 7 — COMMON STOCK AND EARNINGS PER SHARE
The Company reports both basic and diluted earnings per share. Basic earnings per share is computed by dividing income from continuing operations by the weighted average number of common shares outstanding during the period. The calculation of diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period and the repurchase of common shares that would have occurred with proceeds from the assumed issuance. Diluted earnings per share assume the exercise of stock options. Non-vested restricted stock awards are included in the number of common shares outstanding; however, for purposes of computing basic earnings per share, non-vested restricted stock awards are excluded. A reconciliation of both calculations is presented in the following table as of June 30:
                                 
    Three Months     Six Months  
    Ended June 30     Ended June 30  
(in Millions, except per share amounts)   2008     2007     2008     2007  
Basic Earnings per Share
                               
Income from continuing operations
  $ 28     $ 348     $ 228     $ 444  
 
                       
Average number of common shares outstanding
    162       174       162       175  
 
                       
Income per share of common stock based on weighted average number of shares outstanding
  $ 0.17     $ 2.00     $ 1.41     $ 2.53  
 
                       
 
                               
Diluted Earnings per Share
                               
Income from continuing operations
  $ 28     $ 348     $ 228     $ 444  
 
                       
Average number of common shares outstanding
    162       174       162       175  
Incremental shares from stock-based awards
    1       1       1       1  
 
                       
Average number of dilutive shares outstanding
    163       175       163       176  
 
                       
Income per share of common stock assuming issuance of incremental shares
  $ 0.17     $ 1.99     $ 1.41     $ 2.52  
 
                       

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Options to purchase approximately 2 million shares of common stock as of June 30, 2008 were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares, thus making these options anti-dilutive.
NOTE 8 — LONG-TERM DEBT
Detroit Edison converted $238 million of tax-exempt bonds from an auction rate mode to a weekly rate mode in March 2008 due to a loss of liquidity in the auction rate markets. Detroit Edison then repurchased these bonds and held them until such time as it could either redeem and reissue the bonds or remarket the bonds in a longer-term mode. Approximately $187 million of these bonds have been redeemed and reissued and $51 million have been remarketed in a fixed rate mode to maturity.
Debt Issuances
In 2008, the Company has issued or remarketed the following long-term debt:
(in Millions)
                         
Company   Month Issued   Type   Interest Rate   Maturity   Amount  
MichCon
  April   Senior Notes (1)   5.26%   2013   $ 60  
MichCon
  April   Senior Notes (1)   6.04%   2018     100  
MichCon
  April   Senior Notes (1)   6.44%   2023     25  
Detroit Edison
  April   Tax-Exempt Revenue Bonds (2) (3)   Variable   2036     69  
Detroit Edison
  May   Tax-Exempt Revenue Bonds (2) (3)   Variable   2029     118  
Detroit Edison
  May   Tax-Exempt Revenue Bonds (2) (4)   5.30%   2030     51  
MichCon
  June   Senior Notes (5)   6.78%   2028     75  
Detroit Edison
  June   Senior Notes (1)   5.60%   2018     300  
Detroit Edison
  July   Tax-Exempt Revenue Bonds (2) (6)   Variable   2020     32  
 
                     
 
                  $ 830  
 
                     
 
(1)   Proceeds were used to pay down short-term debt and for general corporate purposes.
 
(2)   Detroit Edison Tax-Exempt Revenue Bonds are issued by a public body that loans the proceeds to Detroit Edison on terms substantially mirroring the Revenue Bonds.
 
(3)   Proceeds were used to refinance auction rate Tax-Exempt Revenue Bonds.
 
(4)   These Tax-Exempt Revenue Bonds were previously converted from an auction rate mode and remarketed in a fixed rate mode to maturity.
 
(5)   Proceeds were used to repay the 6.45% Remarketable Securities due 2038 subject to mandatory or optional tender on June 30, 2008.
 
(6)   Proceeds were used to refinance Tax-Exempt Revenue Bonds that matured July 2008.
In June 2008, MichCon entered into a Note Purchase Agreement pursuant to which it agreed to issue and sell $190 million of Senior Notes to a group of institutional investors in a private placement transaction. Pursuant to the agreement, the sale of the notes is expected to close in August 2008. Proceeds are to be used to repay a portion of the $200 million MichCon 6.125% Senior Notes due September 2008.

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Debt Retirements and Redemptions
In 2008, the following debt has been retired, through optional redemption or payment at maturity:
(in Millions)
                         
Company   Month Retired   Type   Interest Rate   Maturity   Amount  
Detroit Edison
  April   Tax-Exempt Revenue Bonds (1)   Variable   2036   $ 69  
Detroit Edison
  May   Tax-Exempt Revenue Bonds (1)   Variable   2029     118  
MichCon
  June   Remarketable Securities (2)   6.45%   2038     75  
Detroit Edison
  July   Tax-Exempt Revenue Bonds (3)   7.00%   2008     32  
 
                     
 
                  $ 294  
 
                     
 
(1)   These Tax-Exempt Revenue Bonds were converted from auction rate mode and subsequently redeemed with proceeds from the issuance of new Detroit Edison Tax-Exempt Revenue Bonds.
 
(2)   These Remarketable Securities were optionally redeemed by MichCon with proceeds from the issuance of new MichCon Senior Notes.
 
(3)   These Tax-Exempt Revenue Bonds were redeemed with the proceeds from the issuance of new Detroit Edison Tax-Exempt Revenue Bonds.
NOTE 9 — COMMITMENTS AND CONTINGENCIES
Environmental
Electric Utility
Air — Detroit Edison is subject to EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. In March 2005, the EPA issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $1.1 billion through 2007. The Company estimates Detroit Edison future capital expenditures at up to $282 million in 2008 and up to $2.4 billion of additional capital expenditures through 2018 to satisfy both the existing and proposed new control requirements.
Water — In response to an EPA regulation, Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of the studies to be conducted over the next several years, Detroit Edison may be required to install additional control technologies to reduce the impacts of the water intakes. Initially, it was estimated that Detroit Edison could incur up to approximately $55 million over the 4 to 6 years subsequent to 2007 in additional capital expenditures to comply with these requirements. However, a recent court decision remanded back to the EPA several provisions of the federal regulation that may result in a delay in compliance dates. The decision also raised the possibility that Detroit Edison may have to install cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies.
Contaminated Sites — Detroit Edison conducted remedial investigations at contaminated sites, including three former manufactured gas plant (MGP) sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. Liabilities accrued for remediation of these sites were approximately $14 million at June 30, 2008 and $15 million at December 31, 2007. The costs to remediate are expected to be incurred over the next several years.
Gas Utility
Contaminated Sites — Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. Gas Utility owns, or previously owned, 15 such former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years.

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The MPSC has established a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites. At June 30, 2008 and December 31, 2007, Gas Utility had liabilities of approximately $38 million and $40 million, respectively, for estimated investigation and remediation costs at former MGP sites and related regulatory assets.
Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. However, the Company anticipates the cost deferral and rate recovery mechanism approved by the MPSC will prevent environmental costs from having a material adverse impact on its results of operations.
Non-Utility
The Company’s non-utility affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants. The Company is in the process of installing new environmental equipment at its coke battery facility in Michigan. The Company expects the project to be completed during 2009. The coke battery facility received and responded to information requests from the EPA resulting in the issuance of a notice of violation regarding potential maximum achievable control technologies and new source review violations. The EPA is in the process of reviewing the Company’s position of demonstrated compliance and has not initiated escalated enforcement. At this time, the Company cannot predict the impact of this issue. The Company’s non-utility affiliates are substantially in compliance with all environmental requirements, other than as noted above.
Other
On July 11, 2008, the U.S. Court of Appeals for the District of Columbia issued a decision (D.C. Circuit Court No. 05-1244 and consolidated cases) vacating the 2005 Clean Air Interstate Rule (CAIR), and remanded it back to the EPA. At June 30, 2008, Detroit Edison had SO2 and NOx emission allowances with a carrying value of $14.5 million and $11.8 million, respectively. The cost of these allowances at Detroit Edison is expected to be recoverable through the PSCR mechanism. At June 30, 2008, the Power and Industrial Projects segment had SO2 and NOx emission allowances with a carrying value of $4.7 million. The Company also has forward contracts for the purchase of SO2 and NOx emission allowances. The Company is currently evaluating the impact of the Court’s decision as the EPA determines its response, and it is not expected to have a material impact on its consolidated financial statements.
Guarantees
In certain limited circumstances, the Company enters into contractual guarantees. The Company may guarantee another entity’s obligation in the event it fails to perform. The Company may provide guarantees in certain indemnification agreements. Finally, the Company may provide indirect guarantees for the indebtedness of others. Below are the details of specific material guarantees the Company currently provides.
Millennium Pipeline Project Guarantee
The Company owns a 26.25% equity interest in the Millennium Pipeline Project (Millennium). Millennium is accounted for under the equity method. Millennium is expected to begin commercial operations in November 2008.
On August 29, 2007, Millennium entered into a borrowing facility to finance the construction costs of the project. The total facility amounts to $800 million and is guaranteed by the project partners, based upon their respective ownership percentages. The facility expires on August 29, 2010. The amount outstanding under this facility was $458 million at June 30, 2008. Proceeds of the facility are being used to fund project costs and expenses relating to the development, construction and commercial start up and testing of the pipeline project and for general corporate purposes. In addition, the facility has been utilized to reimburse the project partners for costs and expenses incurred in connection with the project for the period subsequent to June 1, 2004 through immediately prior to the closing of the facility.
The Company has agreed to guarantee 26.25% of the borrowing facility in the event of default by Millennium. The guarantee includes DTE Energy’s revolving credit facility’s covenant and default provisions by reference. The Company has also provided performance guarantees in regards to completion of Millennium to the major shippers in an amount of approximately $16 million. The maximum potential amount of future payments under these guarantees is approximately $226 million. There are no recourse provisions or collateral that would enable us to recover any amounts paid under the guarantees other than our share of project assets.

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Parent Company Guarantee of Subsidiary Obligations
The Company has issued guarantees for the benefit of various non-utility subsidiaries. In the event that DTE Energy’s credit rating is downgraded below investment grade, certain of these guarantees would require the Company to post cash or letters of credit valued at approximately $903 million as of June 30, 2008. This estimated amount fluctuates based upon commodity prices (primarily power and gas) and the provisions and maturities of the underlying agreements.
Other Guarantees
The Company’s other guarantees are not individually material, with maximum potential payments of $10 million as of June 30, 2008.
Labor Contracts
There are several bargaining units for the Company’s represented employees. Approximately 500 employees in the Company’s electric operations are under a contract that expires in August 2008. The contracts of the remaining represented employees expire at various dates in 2009 and 2010.
Purchase Commitments
Detroit Edison has an Energy Purchase Agreement to purchase steam and electricity from the Greater Detroit Resource Recovery Authority (GDRRA). Under the Agreement, Detroit Edison will purchase steam through 2008 and electricity through June 2024. In 1996, a charge to income was recorded that included a reserve for steam purchase commitments in excess of replacement costs from 1997 through 2008. The reserve for steam purchase commitments totals $9 million as of June 30, 2008 and is being amortized to Fuel, purchased power and gas expense with non-cash accretion expense being recorded through 2008. The Company estimates steam and electric purchase commitments from 2008 through 2024 will not exceed $343 million. In 2003, the Company sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. Under the terms of the sale, Detroit Edison remains contractually obligated to buy steam from GDRRA through December 2008. Also, the Company guaranteed bank loans of $13 million that Thermal Ventures II, LP may use for capital improvements to the steam heating system and during 2007 recorded a liability of $13 million related to the bank loan guarantee.
As of June 30, 2008, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments and energy trading contracts. The Company estimates that these commitments will be approximately $5.9 billion from 2008 through 2051. The Company also estimates that 2008 capital expenditures will be approximately $1.5 billion. The Company has made certain commitments in connection with expected capital expenditures.
Bankruptcies
The Company purchases and sells electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail and other industries. Certain of the Company’s customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. The Company regularly reviews contingent matters relating to these customers and its purchase and sale contracts, and records provisions for amounts considered at risk of probable loss. Management believes the Company’s previously accrued amounts are adequate for probable losses. The final resolution of these matters is not expected to have a material effect on the Company’s consolidated financial statements.
Other Contingencies
The Company is involved in certain legal, regulatory, administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning claims arising in the ordinary course of business. These proceedings include certain contract disputes, additional environmental reviews and investigations, audits, inquiries from various regulators and pending judicial matters. The Company cannot predict the final disposition of such proceedings. The Company regularly reviews legal matters and records provisions for claims it can estimate and which are considered probable of loss. The resolution of these pending proceedings is not expected to have a material effect on the Company’s operations or financial statements in the periods they are resolved.
See Note 6 for a discussion of contingencies related to regulatory matters.

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NOTE 10 — SEGMENT INFORMATION
Beginning in the second quarter of 2008, the Company realigned its Coal Transportation and Marketing business from the Coal and Gas Midstream segment to the Power and Industrial Projects segment, due to changes in how financial information is evaluated and resources allocated to segments by senior management. The Company’s segment information reflects this change for all periods presented. The Company sets strategic goals, allocates resources and evaluates performance based on the following structure:
Electric Utility
    The Company’s Electric Utility segment consists of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 million residential, commercial and industrial customers in southeastern Michigan.
Gas Utility
    The Gas Utility segment consists of MichCon and Citizens. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.3 million residential, commercial and industrial customers throughout Michigan. MichCon also has subsidiaries involved in the gathering, processing and transmission of natural gas in northern Michigan. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.
Non-Utility Operations
    Gas Midstream consists of gas pipelines and storage businesses;
 
    Unconventional Gas Production is engaged in unconventional gas project development and production;
 
    Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers, biomass energy projects and coal transportation and marketing; and
 
    Energy Trading primarily consists of energy marketing and trading operations.
Corporate & Other primarily consists of corporate staff functions that are fully allocated to the various segments based on services utilized. Additionally, Corporate & Other holds certain non-utility debt and energy-related investments.
The income tax provisions or benefits of DTE Energy’s subsidiaries are determined on an individual company basis and recognize the tax benefit of production tax credits and net operating losses. The subsidiaries record income tax payable to or receivable from DTE Energy resulting from the inclusion of its taxable income or loss in DTE Energy’s consolidated federal tax return.
Inter-segment billing for goods and services exchanged between segments is based upon tariffed or market-based prices of the provider and primarily consists of power sales, gas sales and coal transportation services in the following segments:
                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
(in Millions)   2008     2007     2008     2007  
Electric Utility
  $ 2     $ 5     $ 6     $ 9  
Gas Utility
    3       1       3       3  
Gas Midstream
    2       12       5       8  
Unconventional Gas Production
          33             63  
Power and Industrial Projects
    28       62       69       106  
Energy Trading
    40       9       72       17  
Corporate & Other
    (17 )     1       (42 )     2  
 
                       
 
  $ 58     $ 123     $ 113     $ 208  
 
                       

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Financial data of the business segments follows:
                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
(in Millions)   2008     2007     2008     2007  
Operating Revenues
                               
Electric Utility
  $ 1,173     $ 1,210     $ 2,326     $ 2,304  
Gas Utility
    397       311       1,312       1,185  
Non-utility Operations:
                               
Gas Midstream
    17       17       34       33  
Unconventional Gas Production (1)
    13       (287 )     23       (259 )
Power and Industrial Projects
    263       351       514       674  
Energy Trading
    435       197       723       408  
 
                       
 
    728       278       1,294       856  
 
                       
 
                               
Corporate & Other
    11       1       2       2  
Reconciliation & Eliminations
    (58 )     (123 )     (113 )     (208 )
 
                       
Total From Continuing Operations
  $ 2,251     $ 1,677     $ 4,821     $ 4,139  
 
                       
 
                               
Net Income (Loss) by Segment:
                               
Electric Utility
  $ 51     $ 60     $ 92     $ 100  
Gas Utility
    (11 )     (7 )     48       60  
Non-utility Operations:
                               
Gas Midstream
    8       8       16       16  
Unconventional Gas Production (1)(2)
    4       (211 )     86       (209 )
Power and Industrial Projects
    (6 )     9       4       17  
Energy Trading
    (14 )     (13 )     17       (12 )
 
                               
Corporate & Other (3)
    (4 )     502       (35 )     472  
 
                               
Income (Loss) from Continuing Operations
                               
Utility
    40       53       140       160  
Non-utility
    (8 )     (207 )     123       (188 )
Corporate & Other
    (4 )     502       (35 )     472  
 
                       
 
    28       348       228       444  
 
                       
 
                               
Discontinued Operations (Note 4)
          37       12       75  
 
                       
Net Income
  $ 28     $ 385     $ 240     $ 519  
 
                       
 
(1)   2007 Operating Revenues and Net Loss include recognition of losses on hedge contracts associated with the Antrim sale transaction. See Note 4.
 
(2)   2008 Net Income of the Unconventional Gas Production segment in the six month period results primarily from the after-tax gain on the sale of a portion of the Barnett shale properties. See Note 4.
 
(3)   2007 Net Income results principally from the gain recognized on the Antrim sale transaction. See Note 4.

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Part II — Other Information
Item 1. — Legal Proceedings
We are involved in certain legal, regulatory, administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, environmental reviews and investigations, audits, inquiries from various regulators, and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss. The resolution of pending proceedings is not expected to have a material effect on our operations or financial statements in the period they are resolved.
We are aware of attempts by an environmental organization known as the Waterkeeper Alliance to initiate a criminal action in Canada against the Company for alleged violations of the Canadian Fisheries Act. Fines under the relevant Canadian statute could potentially be significant. To date, the Company has not been properly served process in this matter. Nevertheless, as a result of a recent decision by a Canadian court, a trial schedule has been initiated. The Company believes the claims of the Waterkeeper Alliance in this matter are without legal merit and intends to appeal the court’s decision. We are not able to predict or assess the outcome of this action at this time.
Item 1A. — Risk Factors
In addition to the other information set forth in this report, the risk factors discussed in Part 1, Item 1A. Risk Factors in DTE Energy Company’s 2007 Form 10-K, which could materially affect the Company’s businesses, financial condition, future operating results and/ or cash flows should be carefully considered. Additional risks and uncertainties not currently known to the Company, or that are currently deemed to be immaterial, also may materially adversely affect the Company’s business, financial condition, and/ or future operating results.
Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds; Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table provides information about Company purchases of equity securities that are registered by the Company pursuant to Section 12 of the Securities Exchange Act of 1934 during the three months ended June 30, 2008:
                                 
                    Total Number of   Maximum Dollar
                    Shares Purchased   Value that May Yet
    Total Number   Average   as Part of Publicly   Be Purchased Under
    of Shares   Price Paid   Announced Plans   the Plans or
            Period   Purchased (1)   Per Share   or Programs   Programs (2)
04/01/08 - 04/30/08
    22,220       41.46           $ 822,895,623  
05/01/08 - 05/31/08
    32,000       43.13           $ 822,895,623  
06/01/08 – 06/30/08
    35,000       43.72           $ 822,895,623  
Total
    89,220       42.95                
 
(1)   Represents shares of common stock purchased on the open market to provide shares to participants under various employee compensation and incentive programs. These purchases were not made pursuant to a publicly announced plan or program.
 
(2)   In January 2005, the DTE Energy Board of Directors authorized the repurchase of up to $700 million in common stock through 2008. In May 2007, the DTE Energy Board of Directors authorized the repurchase of up to an additional $850 million of common stock through 2009. Through June 30, 2008, repurchases of approximately $725 million of common stock were made under these authorizations. These authorizations provide Company management with flexibility to pursue share repurchases from time to time, and will depend on future asset monetization, cash flows and investment opportunities.

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Item 4. — Submission of Matters to a Vote of Security Holders
(a)   The annual meeting of the holders of Common Stock of the Company was held on May 15, 2008. Proxies for the meeting were solicited pursuant to Regulation 14(a).
 
(b)   There was no solicitation in opposition to the Board of Directors’ nominees, as listed in the proxy statement, for directors to be elected at the meeting and all such nominees were elected.
 
    The terms of the previously elected eight directors listed below continue until the annual meeting dates shown after each name:
         
Alfred R. Glancy III
    2009  
John E. Lobbia
    2009  
Eugene A. Miller
    2009  
Charles W. Pryor, Jr.
    2009  
Anthony F. Earley, Jr.
    2010  
Allan D. Gilmour
    2010  
Frank M. Hennessey
    2010  
Gail J. McGovern
    2010  
(c) At the annual meeting of the holders of Common Stock of the Company held on May 15, 2008, four directors were elected to serve until the annual meeting in the year 2011 and one director (Ruth G. Shaw) was elected to serve until the Annual Shareholder Meeting in the year 2009 with the votes shown:
                 
            Total Vote
    Total Vote   Withheld
    For Each   From Each
    Director   Director
Lillian Bauder
    131,516,937       3,792,957  
W. Frank Fountain, Jr.
    131,950,747       3,359,147  
Josue Robles, Jr.
    131,976,153       3,333,741  
Ruth G. Shaw
    132,072,911       3,236,983  
James H. Vandenberghe
    131,998,870       3,311,024  
Shareholders ratified the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the year 2008 with the votes shown:
         
For   Against   Abstain
131,891,362
  2,505,538   912,994
The Shareholder proposal regarding political contributions was not approved:
         
For   Against   Abstain
24,705,127   58,491,668   14,316,494

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Item 5. — Other Information
None.
Item 6. — Exhibits
     
Exhibit    
Number   Description
 
   
Exhibits filed herewith:
 
   
4-242
  Fortieth Supplemental Indenture, dated as of June 1, 2008 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., Trustee, establishing the 2008 Series F Collateral Bonds.
 
   
4-243
  Seventh Supplemental Indenture, dated as of June 1, 2008 to Supplement to Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee, establishing the 6.78% Senior Notes, 2008 Series F due 2028.
 
   
31-41
  Chief Executive Officer Section 302 Form 10-Q Certification.
 
   
31-42
  Chief Financial Officer Section 302 Form 10-Q Certification.
 
   
Exhibits incorporated herein by reference:
 
   
4-244
  Supplemental Indenture, dated as of May 1, 2008 to Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee, providing for General and Refunding Mortgage Bonds, 2008 Series ET (Exhibit 4-253 to The Detroit Edison Company’s Form 10-Q for the quarter ended June 30, 2008).
 
   
4-245
  Twenty-Fourth Supplemental Indenture, dated as of May 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee, providing for 2008 Series ET Variable Rate Senior Notes due 2029 (Exhibit 4-254 to The Detroit Edison Company’s Form 10-Q for the quarter ended June 30, 2008).
 
   
4-246
  Supplemental Indenture, dated as of June 1, 2008 to Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee, providing for General and Refunding Mortgage Bonds, 2008 Series G (Exhibit 4-255 to The Detroit Edison Company’s Form 10-Q for the quarter ended June 30, 2008).
 
   
4-247
  Twenty-Fifth Supplemental Indenture, dated as of June 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee, providing for 2008 Series G 5.60% Senior Notes due 2018 (Exhibit 4-256 to The Detroit Edison Company’s Form 10-Q for the quarter ended June 30, 2008).
 
   
4-248
  Supplemental Indenture, dated as of July 1, 2008 to Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee, providing for General and Refunding Mortgage Bonds, 2008 Series KT (Exhibit 4-257 to The Detroit Edison Company’s Form 10-Q for the quarter ended June 30, 2008).
 
   
4-249
  Twenty-Sixth Supplemental Indenture, dated as of July 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee, providing for 2008 Series KT Variable Rate Senior Notes due 2020 (Exhibit 4-258 to The Detroit Edison Company’s Form 10-Q for the quarter ended June 30, 2008).
 
   
Exhibits furnished herewith:
 
   
32-41
  Chief Executive Officer Section 906 Form 10-Q Certification.
 
   
32-42
  Chief Financial Officer Section 906 Form 10-Q Certification.

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Table of Contents

SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
 
  DTE ENERGY COMPANY    
 
  (Registrant)    
 
       
Date: August 7, 2008
  /s/ PETER B. OLEKSIAK
 
Peter B. Oleksiak
   
 
  Vice President and Controller and    
 
  Chief Accounting Officer    

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